Advanced NMR Analysis of Porosity and Other Properties in Core Samples using Hydraulic Fluid Exchange

ABSTRACT

A method for determining the porosity of a core sample can include: saturating a core sample with a nuclear magnetic resonance (NMR) saturation fluid, wherein the core sample has a permeability of 100 milliDarcy (mD) or less, to achieve a saturated core sample; taking a NMR measurement of fluids in the saturated core sample; determining a porosity of the core sample based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration.

CROSS REFERENCE TO RELATED APPLICATION

This application claims priority to U.S. Provisional Application Nos.62/847,000, 62/847,001, 62/847,003, 62/847,008, 62/847,012, and62/847,014 all filed May 13, 2019, the disclosures of which areincorporated herein by reference in its entirety.

BACKGROUND

The present disclosure relates to nuclear magnetic resonance (NMR)analysis of core samples.

During oil and gas exploration, zones with higher concentrations of oiland gas can be identified as target zones. One method of identifyingtarget zones is using NMR analysis with core samples and/or loggingtechniques. NMR logging has shown promise in some formations. However,the NMR signals from water overlap with the NMR signals from oil insmall pores. Therefore, NMR logging in tight shale (and similarformations that comprise a substantial amount of small pores) has beenunreliable, to date, for identifying target zones.

Additionally, in many formations, the oil and gas is typically readilyproduced from target zones. However, in tight shale formations, the porenetwork may not be conducive to production. That is, a target zone maybe identified and the formation stimulated for enhanced oil recovery.Initially, the production is quite quick after stimulation but candecline rapidly because the oil and gas located in smaller pores is moredifficult to extract. Identifying properties that relate to potentialoil recovery (e.g., pore connectivity) for target zones in tight shalewould be highly beneficial to the industry.

SUMMARY OF THE INVENTION

The present disclosure relates to nuclear magnetic resonance (NMR)analysis of core samples. More specifically, the NMR analyses describedherein relate to determining properties of core samples having apermeability of 100 milliDarcy (mD) or less. These core samples are fromformations like tight shale.

A first nonlimiting example embodiment of the present disclosure is amethod comprising: saturating a core sample with a NMR saturation fluid,wherein the core sample has a permeability of 100 mD or less, to achievea saturated core sample; taking a NMR measurement of fluids in thesaturated core sample; determining a porosity of the core sample basedon a correlation between the NMR measurement and a NMR signal to fluidvolume calibration.

A second nonlimiting example embodiment of the present disclosure is amethod comprising: determining a porosity of a core sample, wherein thecore sample has a permeability of 100 mD or less; saturating the coresample with a NMR saturation fluid to achieve a saturated core sample;taking a NMR measurement of fluids in the saturated core sample; andderiving a volume for a pore type based on the porosity based on acorrelation between the NMR measurement and a NMR signal to fluid volumecalibration, wherein the pore type is selected from the group consistingof a nanopore, a micropore, a macropore, and any combination thereof.Optionally, determining the porosity of the core sample can be via thefirst nonlimiting example embodiment.

A third nonlimiting example embodiment of the present disclosure is amethod comprising: determining a porosity of a core sample, wherein thecore sample has a permeability of 100 mD or less; saturating the coresample with a NMR measurement saturation fluid to achieve a saturatedcore sample; taking a first NMR measurement of fluids in the saturatedcore sample; hydraulically exchanging a hydrophobic fluid or ahydrophilic fluid in the core sample in a hydrophilic NMR exchange fluidor a hydrophobic NMR exchange fluid, respectively; taking a second NMRmeasurement of the fluids in the core sample after hydraulic exchange;deriving a property of the core sample based on the porosity and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable nanopore oil volume, arecoverable micropore oil volume, a recoverable macropore oil volume, anirreducible nanopore hydrocarbon volume, an irreducible microporehydrocarbon volume, an irreducible macropore hydrocarbon volume, and anycombination thereof for the hydrophilic NMR exchange fluid or isselected from the second group consisting of a recoverable nanoporewater volume, a recoverable micropore water volume, a recoverablemacropore water volume, an irreducible nanopore water volume, anirreducible micropore water volume, an irreducible macropore watervolume, and any combination thereof for the hydrophobic NMR exchangefluid. Optionally, determining the porosity of the core sample can bevia the first nonlimiting example embodiment.

A fourth nonlimiting example embodiment of the present disclosure is amethod comprising: determining a porosity of a core sample, wherein thecore sample has a permeability of 100 mD or less; saturating the coresample with a NMR saturation fluid; taking a first NMR measurement offluids in the core sample; hydraulically exchanging a hydrophobic fluidor a hydrophilic fluid in the core sample in a hydrophilic NMR exchangefluid or a hydrophobic NMR exchange fluid, respectively; taking a secondNMR measurement of the fluids in the core sample after hydraulicexchange; and deriving a property of the core sample based on theporosity, a NMR signal to fluid volume calibration, and a comparisonbetween the first NMR measurement and the second NMR measurement,wherein the property of the core sample is selected from the first groupconsisting of a recoverable oil volume, an irreducible hydrocarbonvolume, and any combination thereof when using the hydrophilic NMRexchange fluid or is selected from the second group consisting of arecoverable water volume, an irreducible water volume, and anycombination thereof when using the hydrophobic NMR exchange fluid.Optionally, determining the porosity of the core sample can be via thefirst nonlimiting example embodiment.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of theembodiments, and should not be viewed as exclusive embodiments. Thesubject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to those skilled in the art and having the benefit of thisdisclosure.

FIGS. 1 and 2 are prophetic, nonlimiting examples of T₂ spectra usefulin determining a porosity of a core sample.

FIG. 3 is a plot of the refocusing delay i data after the NMR signalintensity was correlated to volume of dodecane.

FIG. 4 is the high-field ¹H NMR spectrum (400 MHz, 25° C., ambientpressure, spin echo) taken of the fluid in the core sample.

FIG. 5 is the T₂ spectrum for the core sample with pore types labeled.

FIG. 6 is a plot of the NMR signal as a function of refocusing delay iwas measured for chemical shifts that correspond to protons of water andthe protons of hydrocarbons.

FIG. 7 is a plot of NMR signal decay as a function of magnetic fieldgradient expressed in q-vector.

DETAILED DESCRIPTION

The present disclosure relates to NMR analysis of core samples. Morespecifically, the NMR analyses described herein relate to determiningproperties of core samples from ultra-low permeability formations havinga permeability of 100 mD or less, 10 mD or less, alternatively 1 mD orless, or alternatively 10 microDarcy or less. Examples of ultra-lowpermeability formations are shales, carbonates, tight shale, mudstones,and formations with mixtures thereof.

Definitions

As used herein, the term “ultra-low permeability” when referring to aformation or core sample indicates that it has as permeability 10 mD orless (e.g., 1 mD or less or 10 microDarcy or less).

As used herein, the term “fluid” refers to a combination of liquid andgases.

As used herein, the term “hydrocarbon” refers to organic compoundscomposed predominantly of hydrogen and carbon. Hydrocarbons include, butare not limited to, alkanes (e.g., methane, ethane, propane, paraffins),cycloalkanes, aromatic hydrocarbons, asphaltenes, nitrogen-containingaromatics, oxygen-containing aromatics, and sulfur-containing aromatics,and mixtures thereof

As used herein, the term “oil” refers to liquid hydrocarbons at ambientconditions. As used herein, the term “ambient conditions” refers to 20°C. temperature and 101.3 kPa pressure.

As used herein, the term “gaseous hydrocarbons” refers to hydrocarbonsthat are gaseous at ambient conditions (e.g. methane, ethane, propane,paraffins, and the like).

As used herein, the term “gases” refers to molecules that are gaseous atambient conditions (e.g. methane, ethane, propane, paraffins, He, Ar,CO₂).

As used herein, the term “water” is used generally to describe anaqueous fluid and can include fresh water, salt water, brine, brackishwater, and the like. Examples of salts that may be present include, butare not limited to, inorganic salts (e.g., chlorides, sulfates, andcarbonates) of Group I and II elements and organic salts (e.g.,citrates, acetates, formates, and lactates) of Group I and II elementseach along with associated cations (e.g., lithium, sodium, potassium,magnesium, calcium, aluminum, and iron).

As used herein, the terms “bulk volume percent” and “BV %” is volume offluid per volume of core sample expressed in a percentage. As usedherein, the terms “pore volume percent” and “PV %” is volume of fluidper volume of the fluid in core sample expressed in a percentage.

As used herein, the term “porosity” refers to the extent to which asample is composed of spaces or voids, which may be filled with fluids.Porosity can, for example, have the units of BV %.

As used herein, the terms “nanopore,” “micropore,” and “macropore” donot necessarily indicate an absolute size for a pore but rather arerelative terms that relate to the confinement of fluids within a porewhere nanopores are the most confining pore and the smallest of the poretypes, micropores are less confining than nanopores and the medium sizeof the pore types, and macropores are the least confining pore and thelargest of the pore types.

As described below, NMR measurements (e.g., T₂ relaxation times, T₁/T₂ratios, diffusion NMR, and NMR imaging) are used to define each of theseterms instead of the more common IUPAC definitions.

As used herein, the term “nanopore oil volume” refers to the volume ofoil in nanopores. As used herein, the term “nanopore water volume”refers to the volume of water in nanopores. Nanopore oil volume andnanopore water volume can, for example, have units of BV % or PV %.

As used herein, the term “micropore oil volume” refers to the volume ofoil in micropores. As used herein, the term “micropore water volume”refers to the volume of water in micropores. Micropore oil volume andmicropore water volume can, for example, have units of BV % or PV %.

As used herein, the term “macropore oil volume” refers to the volume ofoil in macropores. As used herein, the term “macropore water volume”refers to the volume of water in macropores. Macropore oil volume andmacropore water volume can, for example, have units of BV % or of cm³ offluid per cm³ of total fluid in the core sample.

As used herein, the term “recoverable oil volume” refers to the volumeof oil in a core sample that can be displaced in a hydraulic exchange.Recoverable oil volume depletion has units of BV % or PV %. Preferably,the hydraulic exchange is performed with a fluid that is not misciblewith the oil such as water.

As used herein, the term “recoverable water volume” refers to the volumeof water in a core sample that can be displaced in a hydraulic exchange.Recoverable water volume has units of BV % or PV %.

As used herein, the term “immobile fluid volume” refers to the volume offluid that cannot be hydraulically exchanged. Immobile fluid volume hasunits of BV % or PV %.

As used herein, the term “irreducible hydrocarbon volume” refers to avolume of hydrocarbon (e.g., gas or oil) that is remaining after thesample is hydraulically exchanged with a liquid fluid that is immisciblewith hydrocarbons. Nonlimiting examples of such a fluid is water.Irreducible hydrocarbon volume can, for example, have units of BV % orPV %.

As used herein, the term “irreducible water volume” refers to a volumeof water that is remaining after the sample is hydraulically exchangedwith hydrocarbon (e.g., oil or gaseous hydrocarbons, or mixturesthereof). Irreducible water volume can, for example, have units of BV %or PV %.

As used herein, the term “NMR measurement” refers to detection ofhydrogen atoms (¹H), carbon atoms (¹³C), fluorine atoms (¹⁹F), sodiumatoms (²³Na), or other atoms with non-zero magnetic moment using alow-field, intermediate-field, or high-field NMR and performingspectroscopy measurements, relaxometry measurements, diffusionmeasurements, imaging measurements, or combinations thereof. As usedherein, the term “low-field NMR” refers to a nuclear magnetic resonanceinstrument operating at magnetic field from 25×10⁻⁶ Tesla up to 0.6Tesla. As used herein, the term “intermediate-field NMR” refers to anuclear magnetic resonance instrument operating at magnetic field from0.6 Tesla up to 1.4 Tesla. As used herein, the term “high-field NMR”refers to a nuclear magnetic resonance instrument operating at magneticfield from 1.4 Tesla up to 70 Tesla.

As used herein, the terms “measurement,” “measured data,” andgrammatical variations thereof refer to acquired and processed data.

As used herein, the terms “Carr-Purcell-Meiboon-Gill” or “CPMG” refersto a spin-echo pulse sequence consisting of the steps: (1) a 90° pulsethat creates a transverse magnetization, (2) a spin-echo period(delay-180°-delay block) that determines the decay of the magnetization,which can repeated any number times, and (3) acquisition of the T₂relaxation times.

As used herein, the term “NMR applicable exchange fluid” or “NMRexchange fluid” relative to core samples refers to a fluid that whenexchanged with an existing fluid in the core sample provides a differentNMR signal (e.g., chemical shift) and/or different NMR signal intensity.For example, deuterated water is a NMR applicable exchange fluid forwater because the ¹H NMR signals reduce when deuterated water replacesthe water in the core sample. In another example, fluorinatedhydrocarbons are NMR applicable exchange fluids for hydrocarbons becausethe ¹⁹F NMR signal increases when the fluorinated hydrocarbons replacehydrocarbons and the ¹H NMR signals decrease when the fluorinatedhydrocarbons (preferably perfluorocarbons) replace hydrocarbons.Therefore, fluorocarbons are ¹H NMR applicable exchange fluid and ¹⁹FNMR applicable exchange fluid. As used herein, the term “NMR applicableexchange fluid” can be modified by a specific isotope to indicate whichNMR type of NMR the NMR applicable exchange fluid relates. For example,a ¹H NMR applicable exchange fluid refers to exchange fluid suitable foruse in ¹H NMR measurements. If a specific type of NMR is not specified,the term NMR applicable exchange fluid applies to fluids suitable foruse in any type of NMR.

As used herein, the term “NMR saturation fluid” relative to core samplesrefers to a NMR visible fluid that is used to fill, to the extent it isable, the pores of the core sample. Exchange of fluids in the coresample with a NMR saturation fluid may or may not occur duringsaturation.

As used herein, the term “deuterated hydrocarbon” refers to ahydrocarbon where any number of hydrogens (one to all) has been replacedwith deuterium.

As used herein, the term “¹³C-enriched hydrocarbon” refers to ahydrocarbon where any number of carbons (one to all) has been replacedwith ¹³C carbon.

As used herein, the term “fluorinated hydrocarbon” refers to ahydrocarbon where any number of hydrogens (one to all) has been replacedwith fluorine. As used herein, the term “perfluorinated hydrocarbon”refers to a hydrocarbon where all hydrogens have been replaced withfluorine.

As used herein, the term “chlorinated hydrocarbon” refers to ahydrocarbon where any number of hydrogens (one to all) has been replacedwith chlorine. As used herein, the term “perchlorinated hydrocarbon”refers to a hydrocarbon where all hydrogens have been replaced withchlorine.

To facilitate a better understanding of the embodiments of the presentinvention, the examples of preferred or representative embodiments aregiven throughout the various sections below. In no way should thefollowing examples be read to limit, or to define, the scope of theinvention.

Core Samples

Core samples can be extracted from subterranean formations by knownmethods. Once collected downhole, the core samples can be handled avariety of ways, and the methods of handling can impact the methodsdescribed herein.

Core samples are typically cylindrical sections of a formation extractedby drilling radially from the wellbore into a sidewall of a wellbore.These core samples are often referred to as horizontal core samples orsidewall core samples. However, vertical core samples that arecylindrical sections extracted along the length of the wellbore can alsobe used in the methods described herein. The methods and analysesdescribed herein are not limited by the extraction methods and directionof the core samples.

In a first example, the core samples can be preserved at formationpressure and temperature. In such cases, NMR analyses for porosity canbe performed directly on the as-received, preserved core sample. Onceinitial NMR measurements are performed, the temperature and pressureconditions of the core samples can be changed. The amount andcomposition of the gas and liquid that elute from the preserved coresample can be measured. Then, these measurements can be used whenderiving other core sample or formation properties (described furtherherein).

In another example, the core samples can be extracted from the formationand allowed to come to ambient temperature and/or pressure as the coringtool ascends from the collection location to the top of the borehole. Insome instances, the amount and composition of the gas and liquid thatelute from the core sample can be measured (e.g., during ascension orcollected during ascension and measured later). Then, these measurementscan be used when deriving other core sample or formation properties.

In another example, core samples can be extracted from the formation andallowed to come to ambient temperature and/or pressure as the coringtool ascends from the collection location to the top of the boreholewhere only a portion of or none of the gas and liquid that elute fromthe core sample is preserved. In these instances, some measurements mayoptionally be taken during production to provide a more completeestimation of the other core sample or formation properties. When thecore sample is not preserved it is still possible to derive all of theinformation about all of the fluid properties described herein (e.g.,recoverable oil volume, recoverable water volume, porosity, and thelike).

NMR Measurement Methods

In the methods of the present invention, one or more NMR methods can beimplemented. NMR measurement methods can include the steps of sendingone or more radiofrequency (RF) pulses and detecting NMR signals fromfluids inside and outside of the core sample. The NMR signals cancorrespond to, for example, a free induction signal (T₂*), a spin echosignal (T₂), a stimulated echo signal, a train of spin or stimulatedecho signals (T₂), a thermal equilibrium signal (T₁) , and anycombination thereof. Various NMR measurement methods can be utilizedinclude, but are not limited to, spectroscopy, diffusometry,1-dimensional imaging, 2-dimensional imaging, 3-dimensional imaging, andany combination thereof. Further, two or more of the NMR signals can becorrelated in a multi-dimensional plot (e.g., a spectroscopicallyresolved T₂, diffusion or imaging plots, or a T₁-T₂ 2-dimensionalcorrelation map).

The free induction decay (FID) describes magnetic field heterogeneitycreated by non-ideality of applied external magnetic field, internalmagnetic field gradients caused by differences of magneticsusceptibilities of fluids and minerals in the core sample and localmagnetic fields derived by surrounded atoms.

NMR spectroscopy determines differences in resonance frequencies causedby local chemical environments (e.g., ¹H—O versus ¹H—C). NMRspectroscopy quantitatively defines signals from different chemicals andfluids such as water ('H—O—¹H) and hydrocarbons (¹H—C— and ¹H═C—).

The relaxation time T₂* describes the time constant for the loss ofphase coherence of the transverse magnetization after the radiofrequency(RF) excitation field is turned off This time dependent loss of phasecoherence may be referred to as the free induction decay.

The time constant T₂ describes the characteristic decay time for theloss of phase coherence of the transverse magnetization following anapplication of two (or more) RF pulses. If two RF pulses are appliedwhich are separated in time by τ, a NMR nuclear spin echo is formed attime 2τ. The time dependence of the amplitude of the echo is describedby T₂ relaxation mechanism. In this mode of measurement, the pair of RFpulses is repeated by successively increasing the delay time τ, betweenthe first and second RF pulse. In an alternative embodiment of thismethod, known as the CPMG pulse sequence, a long series of RF“refocusing” pulses are applied every 2τ, time intervals following thefirst pulse. This generates a spin echo following every time period τ,following the second pulse.

The relaxation time T₁ is the characteristic time for the longitudinalmagnetization to return to thermal equilibrium. There are differentexperimental approaches for measuring the T₁ value. One common method isthe so-called inversion recovery method in which a sufficiently strongRF pulse is appropriately applied to either squelch or actually invertthe magnetization. The return to thermal equilibrium is then monitoredby sampling the state of the magnetization over time either by a seriesof free induction measurements or spin echo measurements.

The diffusometery NMR measurement methods use a pulse sequence tospatially encode and decode the magnetization of molecules. Typically, aHahn-echo or stimulated-echo pulse sequence is used. Measurementsprovide the distribution of spin displacements over the observationperiod of time to calculate the distribution of self-diffusioncoefficient(s) of molecule(s) including those inside the core sample(with slower self-diffusion) and outside of core sample (with fasterself-diffusion).

The imaging NMR measurement methods determine the spatial distributionof spin densities inside and outside of core sample. NMR imagingdetermines the heterogeneity of the fluid inside the core sample as wellas presence of NMR visible fluid (e.g., water, oil) outside of the coresample.

Generally, the nuclei of unique substances will generate uniqueresponses (e.g. relaxation times). Hence, one excitation pulse maypermit measurement of multiple substances in a particular volume. Forexample, water displays a different response than oil, allowingdifferentiation between the two depending on the proton or nuclei'sresponse to the excitation pulse. Also, substances having differentphysical states will respond differently. For example, ice responds toan excitation pulse differently from water because of the structurednature of ice crystals. More particularly, in this example, the magneticmoment of hydrogen nuclei in ice and snow returns to its equilibriumstate so quickly that it becomes undetectable or “invisible” to standardNMR equipment.

A NMR signal to fluid volume calibration correlates a measured NMRsignal to a volume. Such a calibration can be obtained by a variety ofmethods. In a first example, the fluid of interest for the calibrationcan be diluted at various concentrations in a host fluid. The fluid ofinterest and the host fluid should be readily distinguishable by NMR.For example, diluting 1 mL of water in 19 mL of deuterated water andmeasuring the NMR signal from the entire 20 mL provides a NMR signalcorresponding to 1 mL of water in a 20 mL volume or 5 BV %. A series ofsuch dilutions can be done to create the NMR signal to fluid volumecalibration. Then, when measuring NMR signals of fluids in a core sampleby the same NMR measurement method and under the same conditions (e.g.,magnetic strength, pulse sequence, temperature, and the like), thevolume of the sample that the NMR signal measures and the NMR signalintensity can be correlated to a volume of fluid based on the NMR signalto fluid volume calibration.

In another example, a vial with 1 mL of water surrounded by 19 mL ofdeuterated water can be used to correlate provides the NMR signalcorresponding to 1 mL of water in a 20 mL volume or 5 BV %. A series ofsuch experiments can be done to create the NMR signal to fluid volumecalibration. Then, when measuring NMR signals of fluids in a coresample, the volume of the sample that the NMR signal measures and theNMR signal intensity can be correlated to a volume of fluid based on theNMR signal to fluid volume calibration. It should be noted that thefirst method with direct dilution in the fluid of interest in the hostfluid is preferred and provides a more accurate NMR signal to fluidvolume calibration.

In any method of determining a NMR signal to fluid volume calibration,the density of the nuclei the NMR probes should be taken intoconsideration. Further, in any method of determining a NMR signal tofluid volume calibration, the concentration of nuclei (e.g., ¹H) insamples used for determining the NMR signal to fluid volume calibrationshould be similar to the amount of fluid having ¹H in a core sample. Forultra-low permeability formations, the porosity can be 30 BV % or less,and more likely 15 BV % or less. Therefore, control samples should beNMR invisible fluids with varying low concentrations of NMR visiblefluids. Then, the NMR signal to fluid volume calibration that correlateNMR signal intensity to fluid amount can be more correctly estimated.

The sum of all fluid volumes gives the total fluid filled volume of thecorresponding core sample, which translates to the total fluid filledporosity in BV %. Worth noting is that the 1 mL of brine and 1 mL ofISOPAR™ (a mixture of synthetic isoparaffins, available from ExxonMobilChemical) have similar hydrogen atom density and, therefore, givecomparable NMR signal, which allows for using a similar NMR signal tofluid volume calibrations for both fluids, for example, the NMR signalto fluid volume calibration values may be within about 10% andpotentially within 5% depending on the isoparaffin composition. Thisfinding makes total fluid filled porosity measurements very robust andfluid type independent. This is especially important forcharacterization of unknown fluids with low-field NMR that does notprovide a direct fluid type speciation by spectroscopy.

Hydraulic Exchange

Hydraulic exchange is based on exchanging and displacing a fluid in acore sample using a fluid that is immiscible with at least one of thefluids in the core sample. Hydraulic exchange involves introducing anexchange fluid from outside the core sample using pressure or a changein concentration applied to the exchange fluid outside at least oneportion of the core sample. The fluid is allowed to flow through thecore sample causing fluids in the core sample to be replaced (and/ordisplaced) with the exchange fluid. Optionally, temperature can beelevated during fluid exchange.

In a preferred embodiment of the hydraulic exchange process, a pressuredifferential across the core sample is created that causes an exchangefluid to flow into and through the core sample. In this embodiment it ispreferred to seal or partially seal faces of the core through which itis not desired to have fluid flow. For example, if the sides wall of acylindrical core are sealed and fluid is introduced at one end of thecylinder, the pressure differential over the length of the cylinder canbe up to 12,000 psig, or 6,000 psig, or 1,000 psig, or 500 psig, or 100psig These methods of hydraulic fluid exchange are known in the art.

The number of pore volumes of exchange fluid used in hydraulic exchangemethods can be one or more pore volumes (e.g., 1 pore volume to hundredsof pore volumes, 1 pore volume to 30 pore volumes or more, oralternatively 3 pore volumes to 6 pore volumes, or alternatively 6 porevolumes to 30 pore volumes). If the pore structure of the core isrelatively homogeneous, a relatively sharp displacement front will movethrough the core and the amount of fluid needed to completely exchangethe core can be in a range from 1 to 2 pore volumes. As theheterogeneity of the pore structure increases, the front broadens(becoming “softer”) and the amount of fluid needed for hydraulicexchange increases to a range from 1.5 to 10 pores volumes. In someinstances the core has very high permeability pathways and the fluid isprimarily driven through a small portion of the core such as apermeability streak. In this case the amount of fluid needed forhydraulic exchange can be in a range from 2 to 30 pore volumes. Thenature of the front can be assessed by compositionally monitoring fluidthat elutes from the core as a function of time of by X-ray radiographyor x-ray microtomography as described in King et al. (2018) Petrophysics59 (01), 35-43.

Generally, hydrophilic exchange fluids are used for hydraulic exchangeof hydrocarbon fluids in the core sample, and hydrophobic exchangefluids are used for hydraulic exchange of water in the core samples.However, because pressure is used to drive the flow of fluid, some waterin the core sample may be replaced with a hydrophilic exchange fluid,especially if the water is in larger pores or cracks that allows forhydraulic fluid flow more readily than in smaller pores. The same mayalso occur with hydrocarbon fluids and hydrophobic exchange fluids.

Examples of hydrophilic ¹H NMR applicable exchange fluid can include,but are not limited to, deuterated water (D₂O), deuterated alcohols(e.g., deuterated methanol, deuterated ethanol, deuterated isopropanol,deuterated t-butanol, and the like), deuterated glycols (e.g.,deuterated ethylene glycol, deuterated propylene glycol, and the like),chlorinated alcohols, chlorinated glycols, fluorinated alcohols,fluorinated glycols, and any combination thereof

Examples of hydrophobic ¹H NMR applicable exchange fluid can include,but are not limited to, ISOPAR™, deuterated C₁-C₂₀ hydrocarbons (e.g.,deuterated methane, deuterated ethane, deuterated propane, deuteratedbutane, deuterated pentane, deuterated hexane, deuterated cyclohexane,deuterated toluene, and the like), chlorinated C₁-C₂₀ hydrocarbons,fluorinated C₁-C₂₀ hydrocarbons, and any combination thereof

Examples of hydrophilic ¹³C NMR applicable exchange fluid can include,but are not limited to, alcohols (e.g., methanol, ethanol, isopropanol,t-butanol, and the like), glycols (e.g., ethylene glycol, propyleneglycol, and the like), and any combination thereof

Examples of hydrophobic ¹³C NMR applicable exchange fluid can include,but are not limited to, ¹³C enriched C₅-C₂₀ hydrocarbons (e.g., ¹³Cenriched pentane, ¹³C enriched hexane, ¹³C enriched cyclohexane, ¹³Cenriched, and the like), and any combination thereof

Examples of hydrophilic ¹⁹F NMR applicable exchange fluid can include,but are not limited to, fluorinated alcohols, fluorinated glycols, andany combination thereof

Examples of hydrophobic ¹⁹F NMR applicable exchange fluid can include,but are not limited to, fluorinated C₁-C₂₀ hydrocarbons.

Examples of hydrophilic ²³Na H NMR applicable exchange fluid caninclude, but are not limited to, water comprising sodium salts likeNaCl.

Examples of hydrophobic ²³Na NMR applicable exchange fluid can include,but are not limited to, sodium containing ionic liquids.

Each of the foregoing exchange fluid examples may be partiallydeuterated or completely deuterated, partially chlorinated orperchlorinated, or partially fluorinated or perfluorinated, asapplicable to the chemical composition. Preferably, the exchange fluidexamples are completely deuterated, perchlorinated, or perfluorinated,as applicable to the chemical composition.

Typically, the amount NMR signal correlates to the volume of fluid beinganalyzed. The exchange fluid can be NMR active and cause an increase tothe NMR signal or can be NMR invisible and cause a decrease in NMRsignal. The NMR analysis can involve monitoring and analyzing changes toNMR signals over time to derive a variety of core sample attributes(e.g., a porosity, pore type distribution, nanopore oil volume, nanoporewater volume, micropore oil volume, micropore water volume, macroporeoil volume, macropore water volume, initial oil saturation volume,complete oil saturation volume, initial water saturation volume,complete water saturation volume, recoverable oil volume, recoverablewater volume, irreducible hydrocarbon volume, irreducible water volume,and immobile fluid volume, described further herein).

During hydraulic exchange and/or during NMR analysis the core samples,the core samples and corresponding fluid inside and outside of the coresamples can be at an elevated temperature. Generally, when the exchangefluid is a liquid, the elevated temperature should be below the boilingpoint of the fluid at the pressure of the fluid (described below).Suitable temperatures can be ambient up to about 250° C., alternatively50° to 150° C.

Further, during NMR analysis, the core samples can be exposed to aconfining pressure. For example, the samples may be pressurized toapproximate downhole conditions. The core samples can be exposed to aconfining pressure of up to 7,500 psig, and the fluid can be exposed toa pressure sufficient to create a pore pressure up to 6,000 psig andtemperature up to 300° F.

Before and/or after hydraulic exchange, the mass of the core sample withfluid therein can be taken and compared.

Saturation

Saturating a core sample with a NMR saturation fluid may be done by anysuitable method including, but not limited to, hydraulically pushing theNMR saturation fluid into the core sample.

The core samples are preferably as received core samples that stillcontain native fluids. Therefore, while the temperature can be elevatedwhen saturating the core sample, preferably ambient temperature ismaintained to mitigate native fluid in the core sample from exchangingwith the NMR saturation fluid. However, exchange of native fluids in thecore sample for the NMR saturation fluid may occur during saturation.

Any NMR saturation fluid can be used. Preferably, the NMR saturationfluid is water or a hydrocarbon based on the fluid that would haveotherwise been present downhole. For example, the NMR saturation fluidcan be selected based on the type of fluid released from the core samplefrom when the core sample was collected to when the saturation occurred.In another example, for a core sample from a production well or a coresample from a similar geophysical environment where productioncomposition known, the produced fluid may be used to guide which NMRsaturation fluid to use. NMR saturation fluid type should match the typeof fluid predominantly present in the fluid presumed to be presentdownhole. That is a hydrocarbon NMR saturation fluid should be used whenhydrocarbons are presumed to be the downhole fluid, and water should beused when water is presumed to be the downhole fluid.

Examples of hydrocarbon NMR saturation fluids include, but are notlimited to, ISOPAR™, C₅-C₄₀ hydrocarbons (e.g., toluene, xylene,heptane, hexatricontane, and mixtures of linear paraffins), and thelike, and combinations thereof

Examples of hydrophilic NMR saturation fluids include, but are notlimited to, water, and the like.

Porosity

Porosity provides an indication of the total amount of fluid in aformation. Further herein is described how to derive compositionaldetails and mobility information about the fluid in the formation.

When the core is preserved the porosity can be measured in the preservedstate where the sample is saturated with fluid. In this case theporosity is determined by correlating the NMR signal attributed to theliquid in the core sample to a volume. As discussed above, a NMR signalto fluid volume calibration, calibrated with a known amount of fluid,can be used to quantitatively correlate NMR signal intensity to volumeof each fluid phase.

If the sample is not preserved the porosity of a core sample can bedetermined by saturating the core sample with a NMR saturation fluid. Asdiscussed above, a NMR signal to fluid volume calibration, calibratedwith a known amount of fluid, can be used to quantitatively correlateNMR signal intensity to volume of each fluid phase.

Alternatively, porosity on a non-preserved core can be determinedwithout hydraulic exchange if, from an independent means, it isdetermined that less than 25%, preferably less than 10%, even morepreferably less than 5% of the fluid accessible pores are not filledwith fluid. For example, the empty pore space can be assessed bymeasuring NMR signals before and after saturation of cores from asimilar geophysical environment.

The NMR signal from the fluid in the core sample (e.g., native fluidand/or the NMR saturation fluid) can be used to estimate the porosity ofthe core sample.

In one example, a T₂ spectrum can be measured. Generally, as describedbelow relative to fluid volume for different pore types, T₂ relaxationtimes above about 300 ms correspond to the fluid surrounding the coresample (or free fluid). The integral of the area under the T₂ relaxationcurve for relaxation times below 300 ms correlates to the total volumeof the fluid via a NMR signal to fluid volume calibration. The NMRsaturation fluid should be selected to have a T₂ relaxation time whennot confined in a core sample of greater than 300 ms or additionalcorrection factors should be applied. Examples of fluids with T₂relaxation times greater than 300 ms when not confined by a core sampleinclude, but are not limited to, ISOPAR™, C₅-C₄₀ hydrocarbons (e.g.,toluene, xylene, heptane, hexatricontane, and mixtures of linearparaffins), water, and the like, and combinations thereof. Preferably,C₅-C₄₀ alkanes including mixtures thereof are used as NMR saturationfluids in this method.

FIGS. 1 and 2 are prophetic, non-limiting examples of T₂ spectra usefulin determining a porosity of a core sample. In both figures, there areseveral T₂ intensity peaks from 0.1 ms to 300 ms that correspond to NMRsignals from toluene inside the core sample. Above 300 ms, the NMRsignal is from the fluid external to the core sample. The areas underthe T₂ spectrum from 0.1 ms to 300 ms correlates (per the NMR signal tofluid volume calibration) to the volume of fluid in the core sample and,consequently, the porosity.

Accordingly, a method of the present disclosure for determining aporosity of a core sample can include saturating a core sample with aNMR saturation fluid, wherein the core sample has a permeability of 100mD or less, to achieve a saturated core sample; taking a NMR measurementof the saturated core sample; determining a porosity of the core samplebased on a correlation between the NMR measurement and a NMR signal tofluid volume calibration, wherein the NMR measurement is ¹H T₂relaxation times measured with low-field and/or intermediate-field NMRand the correlation is between an area under a ¹H T₂ relaxation timespectrum of the core sample from 0.1 ms to 300 ms and the NMR signal tofluid volume calibration.

In another example using a different NMR measurement, in T₁-T₂2-dimensional correlation map, lower T₁ and lower T₂ values correspondto fluids confined by in the pore structure of a core sample. Forexample, measuring the ¹H T₁ and ¹H T₂ relaxation times with low-fieldand/or intermediate-field NMR, ¹H T₁ of 0.1 ms to 300 ms and ¹H T₂ of0.1 ms to 300 ms correspond to water and hydrocarbon confined in thepore structure of a core sample. Accordingly, using a NMR signal tofluid volume calibration, the volume of fluid in the core sample can bedetermined from the area under the T₁-T₂ 2-dimensional correlation mapfor ¹H T₁ of 0.1 ms to 300 ms and ¹H T₂ of 0.1 ms to 300 ms. Whendescribing the area under a map herein, it is the integral of the z-axis(e.g., signal intensity) for the provided range(s) of the x- and/ory-axes (e.g., T₁ relaxation time and/or T₂ relaxation time).

Accordingly, a method of the present disclosure for determining aporosity of a core sample can include saturating a core sample with aNMR saturation fluid, wherein the core sample has a permeability of 100mD or less, to achieve a saturated core sample; taking a NMR measurementof the saturated core sample; determining a porosity of the core samplebased on a correlation between the NMR measurement and a NMR signal tofluid volume calibration, wherein the NMR measurement is ¹H T₁-T₂2-dimensional correlation map measured with low-field and/orintermediate-field NMR and the correlation is between an area under a ¹HT₁-T₂ relaxation time plot of fluid in the core sample from T₂ of 0.1 msto 300 ms and T₁ of 0.1 ms to 300 ms and the NMR signal to fluid volumecalibration.

In another example method, a low-field NMR can be used in relaxometerymode for collecting T₂ relaxation times with a variable refocusing delaytime τ, also referred to herein as a NMR signal decay. Then, the totalproton content (which relates to the total fluid present as describedabove) is obtained by extrapolating the relaxation time to zero time.For ultra-low permeability core samples, the fluid in the smaller poresis more clearly resolved with shorter refocusing delay time i below 200μs, preferentially below 50 μs.

In another example using a different NMR measurement, a low-field NMRcan be used in relaxometery mode for collecting T₂ relaxation times witha variable refocusing delay time τ, also referred to herein as a NMRsignal decay. Then, the total proton content (which relates to the totalfluid present as described above) is obtained by extrapolating (e.g., c)the relaxation time to zero refocusing delay. The NMR signal intensitycan be converted to fluid volume based on NMR signal to fluid volumecalibration to yield a plot of fluid volume as a function of refocusingdelay τ. Then, the area under the fit corresponds to the porosity. Forultra-low permeability core samples, the fluid in the smaller pores ismore clearly resolved with shorter refocusing delay time τ below 200 μs,preferentially below 50 μs.

EXAMPLE 1

The fluid in a core sample was hydraulically exchanged for dodecane.Then, the low-field NMR measurements (CPMG, 2 MHz, 25° C.) of the fluidin the core sample were taken. FIG. 3 is a plot of the NMR signal fromthe sample as a function of refocusing delay τ. NMR signal intensity wascorrelated to a known volume of dodecane. The extrapolation of the datato zero time corresponds to the volume of dodecane in the core sampleand, consequently, the porosity. In this example, the dodecane volumewas 1.2 mL, which is 9.3 BV %.

Accordingly, a method of the present disclosure for determining aporosity of a core sample can include saturating a core sample with aNMR saturation fluid, wherein the core sample has a permeability of 100mD or less, to achieve a saturated core sample; taking a NMR measurementof the saturated core sample; determining a porosity of the core samplebased on a correlation between the NMR measurement and a NMR signal tofluid volume calibration, wherein the NMR measurement is T₂ NMR signalintensity as a function of refocusing delay and the correlation isbetween a y-value at a y-intercept of an extrapolation of the T₂ NMRsignal intensity including x=0 and the NMR signal to fluid volumecalibration.

In yet another example method, a high-field ¹H NMR or ¹³C NMR can beused where the chemical shift reflects the type of fluid (e.g.,hydrocarbon and water for ¹H NMR or hydrocarbon for ¹³C NMR). Then, thearea under the signal for specified chemical shift ranges can becorrelated to specific fluid concentrations.

EXAMPLE 2

The porosity was measured for a core sample from a large off-shorecarbonate oil field. A crude oil hydrocarbon fluid was hydraulicallyexchanged for at least a portion of the fluid in the core sample,achieving irreducible water conditions FIG. 4 is the high-field ¹H NMRspectrum (400 MHz, 25° C., ambient pressure, spin echo) taken of thefluid in the core sample. The NMR spectrum has three broad peaks from a¹H chemical shift of −1 ppm to 9.5 ppm. Because oil and water havedifferent proton densities, their correlation factor from NMR signalintensity to fluid amount are different. The three broad peaks weredeconvoluted with a peak centered at about 4 ppm to 6 ppm beingattributed to water and the two peaks centered at about 0 ppm to 2 ppmand 6 ppm to 8 ppm being attributed to hydrocarbon (aliphatic andaromatic fractions, respectively). Comparison with scaled NMR signalfrom known amount of water and oil gives the fluid amount in the sampleand the porosity was determined to be 24.3 BV % with 21.7 BV % being oilfilled and 2.6 BV % being water filled.

Accordingly, a method of the present disclosure for determining aporosity of a core sample can include saturating a core sample with aNMR saturation fluid, wherein the core sample has a permeability of 100mD or less, to achieve a saturated core sample; taking a NMR measurementof the saturated core sample; determining a porosity of the core samplebased on a correlation between the NMR measurement and a NMR signal tofluid volume calibration, wherein the NMR measurement is ¹H spectroscopymeasured with high-field NMR and the correlation is between an areaunder a ¹H spectrum of a fluid in the core sample from 10 ppm to 0 ppmand the NMR signal to fluid volume calibration.

In yet another example with a different NMR measurement, the T₁/T₂ratios of the fluids can be measured. T₁/T₂ ratios above 1 correspond tofluid confined by the pore structure of the core sample. For example,for low-field and/or intermediate-field NMR, 1<¹H T₁/T₂ ratio<100corresponds to fluid in the pore structure of the core sample.Accordingly, an area under the curve of a plot of signal intensity as afunction of ¹H T₁/T₂ ratio for 1<¹H T₁/T₂ ratio<100 can be correlated toa volume of fluid in the core sample and, consequently, a porosity ofthe core sample using a NMR signal to volume calibration. T₁-T₂2-dimensional correlation map is also used to define volumes of waterand oil.

Accordingly, a method of the present disclosure for determining aporosity of a core sample can include saturating a core sample with aNMR saturation fluid, wherein the core sample has a permeability of 100mD or less, to achieve a saturated core sample; taking a NMR measurementof the saturated core sample; determining a porosity of the core samplebased on a correlation between the NMR measurement and a NMR signal tofluid volume calibration, wherein the NMR measurement is ¹H T₁/T₂ ratiomeasured with low-field and/or intermediate-field NMR and thecorrelation is between an area under a ¹H T₁/T₂ ratio of 1<¹H T₁/T₂ratio≤100 of a fluid in the core sample and the NMR signal to fluidvolume calibration.

In yet another example, the core sample can be imaged by NMR imagingmethods where a T₂- and T₁-relaxation corrected signal for the fluidwithin the spatial boundaries of the core sample can be correlated tofluid volume and, consequently, porosity of the core sample using a NMRsignal to volume calibration.

Accordingly, a method of the present disclosure for determining aporosity of a core sample can include saturating a core sample with aNMR saturation fluid, wherein the core sample has a permeability of 100mDor less, to achieve a saturated core sample; taking a NMR measurementof the saturated core sample; determining a porosity of the core samplebased on a correlation between the NMR measurement and a NMR signal tofluid volume calibration, wherein the NMR measurement is imagingmeasured with intermediate-field and/or high-field NMR and thecorrelation is between a T₂- and T₁-relaxation corrected signal for afluid within spatial boundaries of the core sample and the NMR signal tofluid volume calibration.

In any of the foregoing example, the composition of the fluid thatelutes from the core sample during hydraulic exchange can be analyzed.

Pore Type Distribution, Micropore Oil Volume, Macropore Oil Volume,Micropore Water Volume, and Macropore Water Volume

Extracting oil from different size pores can require differentproduction techniques. Generally, oil in contact with the rock can bemore difficult to produce because of interactions between the rock andthe oil. Therefore, larger volumes of oil in macropores may be moreeasily produced because the volume to surface area ratio of themacropores is greatest.

Production of oil from micropores and nanopores may require additionalinterventions like chemical floods or steam injection. Accordingly,knowing the volume of oil in each of these pore structures may providevaluable insight to the production methods needed for different areas ofthe reservoir.

Conversely, water in different pore types can create different issues.Generally, water production is preferably minimal. As in oil above,water in the larger pores is more readily produced. Current methods onlyprovide an estimated amount of water in the reservoir. However, if mostof that water is in nanopores, then water production could be minimaland less costly water mitigation technique could be implemented tominimize water in the produced fluid. However, if the water is primarilyin macropores, then a more aggressive approach may be used to mitigatewater production. Alternatively, that portion of the formation may bebypassed for production.

Knowing the distribution of pore types and the distribution of waterand/or oil in the different pore types would be useful in developing aproduction plan for a wellbore.

When determining a pore size distribution or volumes of fluids indifferent pore types, the entire porosity is preferably filled. For coresamples that are not sealed with the formation fluids therein, thelarger pores can be at least partially empty because fluids therein caneasily flow out. Accordingly, the core sample should be first saturatedwith a NMR saturation fluid and maintain saturation during the NMRmeasurement(s). Maintaining saturation can involve either maintainingthe core sample submerged in a fluid bath and/or in a pressure cell.

The NMR response of fluids in different pore types is affected by thevolume to surface area ratio and the relative confinement. For thevolume to surface area ratio, the composition of the rock in theformation can influence a nuclei's NMR response when in close proximityto the rock surface. Therefore, the composition of the rock has lessinfluence on the NMR response of fluids in macropores as compared tonanopores. Relative confinement is similar except it is the mobility ofthe fluid molecule within the pore. Because nanopores are so small thenatural movement of the fluid therein is limited. As fluid mobility islimited, the molecules may assemble or orient to some degree and theneighboring fluid molecules could have an effect on a nuclei's NMRresponses.

Because of the volume to surface area ratio and the relative confinementof fluids within the different pores, the fluids in the different poreshave different NMR responses. For example, fluids in nanopores are themost confined and interact with the rock the most. Accordingly, thefluids in nanopores have a shorter T₂ relaxation time. The fluids inmicropores are less confined and interact less with the rock and,therefore, have longer T₂ relaxation times. Continuing the trend, thefluid in macropores have even longer T₂ relaxation times, followed byexternal or free fluid with the longest T₂ relaxation times.

The exact ranges of T₂ relaxation times and T₁/T₂ ratios associated witheach of the pore types will depend on the composition of the rock andthe pore surface, the composition of the fluids, the magnetic fieldstrength, and the temperature of the sample. Tables 1 and 2 provide twononlimiting examples of conditions with the corresponding ¹H NMR T₂relaxation time ranges and ¹H T₁/T₂ ratio ranges, respectively. Othernuclei, magnetic fields, and measurement conditions can be used, and theT₂ relaxation time ranges and T₁/T₂ ratio ranges corresponding to poretype can be readily determined by one skilled in the art based on theteachings of the present disclosure.

TABLE 1 Parameters Temperature 25° C. NMR Acquisition Parameterslow-field and/or intermediate- field NMR T₂ Relaxation Ranges Pore TypeRange Nanopores 0.1 ms ≤ T₂ < 1.5 ms Micropores 1.5 ms ≤ T₂ < 30 ms Macropores  30 ms ≤ T₂ < 300 ms External or Free Fluid 300 ms andgreater

TABLE 2 Parameters Temperature 25° C. NMR Acquisition Parameters low-field and/or intermediate- field NMR T1/T2 Ratio Ranges Pore TypeRange Nanopores 10 < T1/T2 ≤ 100 Micropores 3 < T1/T2 ≤ 10 Macropores 1< T1/T2 ≤ 3  External or Free Fluid   T1/T2 = 1

Once the NMR measurements are performed, the area under the T₂ spectrumrelates to the volume of fluid in the pores. Knowing the porosity or,more specifically, the volume of voids in the core sample, the areaunder the T₂ spectrum for the three pore types (0.1 ms≤T₂≤300 ms)cumulatively can be assigned to 100% of volume of voids. Then, thepercentage of area under the T₂ spectrum for each individual pore typerelative to the total area under the T₂ spectrum up to 300 mscorresponds to a percent volume, from which total volume for eachindividual pore type can be extrapolated.

In an example method, the fluid in a core sample is hydraulicallyexchanged for an exchange fluid, preferably at least two pore volumesworth of exchange fluid. Then, a low-field NMR can be used inrelaxometery mode for collecting T₂ relaxation times with a variablerefocusing delay time τ. Then, the total proton content (which relatesto the total fluid present as described above) for each of the ranges inTable 1 is correlated to the volume of fluid in each pore type and,consequently, a pore type distribution.

For another example, a method of the present disclosure for determiningvolumes of fluids in a pore type can include determining a porosity of acore sample, wherein the core sample has a permeability of 100 mD orless; saturating the core sample with NMR saturation fluid to achieve asaturated core sample; taking a NMR measurement of fluids in thesaturated core sample, wherein NMR measurement is ¹H T₂ relaxation timesmeasured with low-field and/or intermediate-field NMR; deriving a volumefor a pore type based on the porosity and a correlation between the NMRmeasurement and a NMR signal to fluid volume calibration, wherein thepore type is selected from the group consisting of a nanopore, amicropore, a macropore, and any combination thereof, wherein thecorrelation is between the NMR signal to fluid volume calibration and anarea under a ¹H T₂ relaxation time spectrum for one selected from thegroup consisting of 0.1 ms≤T₂<1.5 ms for the nanopores, 1.5 ms≤T₂<30 msfor the micropores, 30 ms≤T₂<300 ms for the macropores, and anycombination thereof

EXAMPLE 3

A the fluid in a core sample (a shale core sample) was hydraulicallyexchanged for toluene. T₂ relaxation measurements (2 MHz, CPMG pulsesequence, 25° C., confinement pressure 4500 psig, pore pressure 3500psig) were performed on the fluids of the core samples. FIG. 5 is the T₂spectra for the core sample with pore types labeled.

The nanopores contain about 1.99 cm³ of toluene, the micropores containabout 1.37 cm³ of toluene, the macropores contain about 0.037 cm³ oftoluene, and the external fluid contains about 0.22 cm³ of toluene.Therefore, the pore type distribution is about 59 PV % nanopores, about40 PV % micropores, and about 1 PV % macropores.

Similar to the previous example based on Table 1, an example based onTable 2 is a method of the present disclosure for determining volumes offluids in a pore type that includes determining a porosity of a coresample, wherein the core sample has a permeability of 100 mD or less;saturating the core sample with a NMR saturation fluid to achieve asaturated core sample; taking a NMR measurement of fluids in thesaturated core sample, wherein the NMR measurement is ¹H T₁/T₂ ratiomeasured with low-field and/or intermediate-field NMR; deriving a volumefor a pore type based on the porosity and a correlation between the NMRmeasurement and a NMR signal to fluid volume calibration, wherein thepore type is selected from the group consisting of a nanopore, amicropore, a macropore, and any combination thereof, wherein thecorrelation is between the NMR signal to fluid volume calibration andthe ¹H T₁/T₂ ratio for one selected from the group consisting of 10−¹HT₁/T₂<100 for the nanopores, 3≤¹H T₁/T₂<10 for the micropores, 1≤¹HT₁/T₂<3 for the macropores, and any combination thereof.

In another example using a different NMR measurement, a ¹H T₁-T₂2-dimensional correlation map can be analyzed to determine volumes offluids in a pore type. For example, a method of the present disclosurefor determining volumes of fluids in a pore type can include determininga porosity of a core sample, wherein the core sample has a permeabilityof 100 mD or less; saturating the core sample with a NMR saturationfluid to achieve a saturated core sample; taking a NMR measurement offluids in the saturated core sample, wherein the NMR measurement is ¹HT₁-T₂ 2-dimensional correlation map measured with low-field and/orintermediate-field NMR; deriving a volume for a pore type based on theporosity and a correlation between the NMR measurement and a NMR signalto fluid volume calibration, wherein the pore type is selected from thegroup consisting of a nanopore, a micropore, a macropore, and anycombination thereof, wherein the correlation is between the NMR signalto fluid volume calibration and an area under the ¹H T₁-T₂ 2-dimensionalcorrelation map for one selected from the group consisting of 0.1ms≤T₂<1.5 ms for the nanopores, 1.5 ms≤T₂<30 ms for the micropores, 30ms≤T₂<300 ms for the macropores, and any combination thereof.

In yet another example using another NMR measurement, T₂-weightedimaging of the fluids within the spatial boundaries of the core samplecan be analyzed to determine volumes of fluids in a pore type. Forexample, a method of the present disclosure for determining volumes offluids in a pore type can include determining a porosity of a coresample, wherein the core sample has a permeability of 100 mD or less;saturating the core sample with a NMR saturation fluid to achieve asaturated core sample; taking a NMR measurement of fluids in thesaturated core sample, wherein the NMR measurement is T₂-weightedimaging; deriving a volume for a pore type based on the porosity and acorrelation between the NMR measurement and a NMR signal to fluid volumecalibration, wherein the pore type is selected from the group consistingof a nanopore, a micropore, a macropore, and any combination thereof,wherein the correlation is between the NMR signal to fluid volumecalibration and a T₂- and T₁-relaxation corrected signal for the fluidswithin spatial boundaries of the core sample where the T₂-weight is 0.1ms≤T₂<1.5 ms for the nanopores, where the T₂-weight is 1.5 ms≤T₂<30 msfor the micropores, and where the T₂-weight is for 30 ms≤T₂<300 ms forthe macropores.

In another example using a different NMR measurement, spectroscopicallyresolved spin echo with the refocusing delay i with a high-field NMRprovides the T₂ signal at the specified chemical shifts and a relativeconcentration of oil in nanopores, micropores, and macropores and arelative concentration of water in nanopores, micropores, and macropores(e.g., as illustrated relative to FIG. 6). FIG. 6 is a plot of therefocusing delay where each of the plots corresponds to a chemical shiftof the peaks in FIG. 4. So, there are two refocusing plots for thehydrocarbon fluid and the water in the core sample. Each set of data isa fit (e.g., to a 2-exponential fit in this example or to a3-exponential fit). For this FIG. 6 example, the slope of the twoexponential factors is related to T₂ time, which can be corresponded toa pore type with a calibration experiment. Because this a high-field NMRexperiment, the T₂ relaxation times will likely not correspond to thelow-field T₂ relaxation times of Table 1. Further, the correspondingpre-exponential factors for the 2-exponential fit relate to the volumesof fluid in the pore types for which the slope of the exponentcorresponds. In this example, there is no detectible fluid in nanopores.However, core samples with all three pore types can be analyzedsimilarly with a 3-exponential fit.

EXAMPLE 4

A carbonate core sample was saturated with oil and water. Thespectroscopically resolved spin echo with the refocusing delay i wasacquired at the specified chemical shifts corresponding to each of thepeaks in FIG. 4. Using NMR signal to fluid volume calibration and therelative NMR signals, the oil in the core sample was determined to be97% in micropores and 3% in macropores, and the water in the core samplewas determined to be 92% in micropores and 8% in macropores. Then, usinga volume percent of each in the total porosity (e.g., as describedrelative to FIG. 4), the amount of oil and water in the micropores andmacropores (i.e., the micropore oil volume, the macropore oil volume,the micropore water volume, and the macropore water volume) can bedetermined. Using the oil and water amounts determined in Example 2, themicropore oil volume is 21 BV %, the macropore oil volume is 0.7 BV %,the micropore water volume is 2.4 BV %, and the macropore water volumeis 0.2 BV %. Therefore, oil saturation is 21.7 BV %, water saturation is2.6 BV %, and total fluid filled porosity is 24.3 BV %.

Accordingly, a method of the present disclosure for determining volumesof fluids in a pore type can include determining a porosity of a coresample, wherein the core sample has a permeability of 100 mD or less;saturating the core sample with a MR saturation fluid to achieve asaturated core sample; taking a NMR measurement of fluids in thesaturated core sample, the NMR measurement is T₂ NMR signal intensity asa function of refocusing delay; deriving a volume for a pore type basedon the porosity and a correlation between the NMR measurement and a NMRsignal to fluid volume calibration, wherein the pore type is selectedfrom the group consisting of a nanopore, a micropore, a macropore, andany combination thereof, wherein the correlation is between the NMRsignal to fluid volume calibration and a multi-exponential fit (e.g., a2-exponential fit or to a 3-exponential fit) of the T₂ NMR signalintensity as a function of refocusing delay where a slope of eachexponential factor in the multi-exponential fit relates to the pore typeand a pre-exponential factor of each exponential factor in themulti-exponential fit relates to the volume of the pore type.

In yet another example method, diffusion NMR (also referred to asself-diffusion NMR) measurements can be used to determine the pore typedistribution and the fluids in each pore type. Diffusion NMR techniquescombine RF pulse with magnetic field gradients to identify spatialmovement of molecules within the fixed observation time. The moreintense and longer the magnetic gradient pulse in these techniques, themore spatially selective the technique is. By monitoring specificchemical shifts that correspond to water and/or hydrocarbons (asdescribed in FIG. 4), the distribution of oil and water mobility isobtained. Further, because the method provides the distance themolecules diffuse over a specific time period, the fraction and volumeof fluid in micropores (shorter travel distance) and macropores (longertravel distance) or in thin layers on the surface of the rock can alsobe determined after correction on signal losses due to T₂ and Tiprocesses, which observed molecules experience during the coding anddecoding experiment.

Example 5

Control samples were prepared with water and/or hydrocarbon notconfined, in microcarbonate pores (simulating micropores), and inzeolite pores (simulating nanopores) to identify self-diffusion valuesfor each. The particles were loaded with water or hydrocarbon (dodecanein this example) and the diffusion rates were measured by NMR(stimulated echo, t_(d)=100 ms, τ=3.5 ms, δ-3 ms, and g=75 G/cm). Table3 includes diffusion rate ranges for the various pore type sizes fordifferent fluids.

TABLE 3 Diffusion Rate (DR) (m²/s) Pore Type Water Hydrocarbon Notconfined 2.7 × 10⁻⁹ m²/s < DR 1 × 10⁻⁹ m²/s < DR and macroporesMicropores 1 × 10⁻¹¹ m²/s < DR ≤ 1 × 10⁻¹¹ m²/s < DR ≤ 2.7 × 10⁻⁹ m²/s 1× 10⁻⁹ m²/s Nanopores 1 × 10⁻¹⁴ m²/s < DR ≤ 1 × 10⁻¹⁴ m²/s < DR ≤ 1 ×10⁻¹¹ m²/s 1 × 10⁻¹¹ m²/s * * Hydrocarbon would not load into thezeolite, so this is an estimated range.

Diffusion NMR data (stimulated echo, t_(d)=100 ms, τ=3.5 ms, δ-3 ms, andg=75 G/cm) was collected on the core sample of Example 2. FIG. 7compares the spectroscopically resolved NMR signal decays from water andoil in the rock sample with bulk water and bulk oil as a function ofmagnetic field gradient expressed in q-vector values, which are thecombination of NMR sequence parameters (e.g., gradient field intensity,gradient field duration, gyromagnetic ratio of nuclei) that give aspatial vector of 1/m². Mobility of oil in the rock sample is reduced bythe factor of approximately 0.1 relative to the diffusion of oil notconfined. Water mobility in the core sample is reduced by the factor of0.006 suggesting water location in smaller pores.

This example illustrates methods by which the pore type can bedetermined using diffusion NMR data. It should be noted that thehydrocarbon diffusion rate is dependent on the viscosity and structureof the hydrocarbon. Accordingly, it is preferred to use hydrocarbonfluids that are relatively small and have good diffusion to mitigatecomposition dependent artifacts in the diffusion rates. For example,ISOPAR™ and C₅-C₁₅ hydrocarbons are preferred.

Accordingly, a method of the present disclosure for determining volumesof fluids in a pore type can include determining a porosity of a coresample, wherein the core sample has a permeability of 100 mD or less;saturating the core sample with a NMR saturation fluid to achieve asaturated core sample; taking a NMR measurement of fluids in thesaturated core sample, wherein the NMR measurement is diffusometry;deriving a volume for a pore type based on the porosity and acorrelation between the NMR measurement and a NMR signal to fluid volumecalibration, wherein the pore type is selected from the group consistingof a nanopore, a micropore, a macropore, and any combination thereof,wherein the correlation is between the NMR signal to fluid volumecalibration and a T₂- and T₁-relaxation corrected area under a diffusionspectrum of the fluids in the core sample for 1×10⁻¹⁴ m²/s<diffusionrate≤1×10⁻¹¹ m²/s for nanopores and/or for 1×10⁻¹¹ m²/s<diffusionrate≤1×10⁻⁹ m²/s for micropores.

Recoverable Oil Volume, Recoverable Water Volume, IrreducibleHydrocarbon Volume, Irreducible Water Volume, and Immobile Fluid Volume

Recoverable oil volume, recoverable water volume, irreduciblehydrocarbon volume, irreducible water volume, and immobile fluid volumeare interrelated properties of the core sample. The immobile fluidvolume is the sum of the irreducible hydrocarbon volume and theirreducible water volume; and the porosity is the sum of the recoverableoil volume, the recoverable water volume, and the immobile fluid volume.

These properties can be determined using NMR measurements at variousstages of hydraulic exchange methods performed on a core samplesaturated with a NMR saturation fluid. For example, a first NMRmeasurement of a saturated core sample where the fluid in the coresample has a NMR signal. Then, the saturated core sample ishydraulically exchanged with a hydrophilic NMR exchange fluid followedby a second NMR measurement where the loss of NMR signal corresponds tothe hydrophobic fluid being forced out of the core sample, which is therecoverable oil volume. Then, the saturated core sample can behydraulically exchanged with a hydrophobic NMR exchange fluid followedby a third NMR measurement where the loss of NMR signal corresponds tothe hydrophilic fluid being forced out of the core sample, which is therecoverable water volume. The NMR signal from fluid remaining in thecore sample is the immobile fluid volume, which can be differentiatedinto irreducible hydrocarbon volume and irreducible water volume by thethird NMR measurement and/or a fourth NMR measurement.

In another example, a first NMR measurement of a saturated core samplewhere the fluid in the core sample has a NMR signal. Then, the saturatedcore sample is hydraulically exchanged with a hydrophobic NMR exchangefluid followed by a second NMR measurement where the loss of NMR signalcorresponds to the hydrophilic fluid being forced out of the coresample, which is the recoverable oil volume. Then, the saturated coresample can be hydraulically exchanged with a hydrophilic NMR exchangefluid followed by a third NMR measurement where the loss of NMR signalcorresponds to the hydrophobic fluid being forced out of the coresample, which is the recoverable water volume. The NMR signal from fluidremaining in the core sample is the immobile fluid volume, which can bedifferentiated into irreducible hydrocarbon volume and irreducible watervolume by the third NMR measurement and/or a fourth NMR measurement.

Each of the foregoing methods alternatively can be completed with onlythe first hydraulic exchange to determine the corresponding recoverablefluid volume if no other properties need to be determined.

The NMR measurements can be used to identify the fluids and amount ofsaid fluids being forced from the core sample. Said NMR measurements canbe those described herein for determining porosity, which include, butare not limited to, the area under high-field ¹H NMR spectrum (e.g., asdescribed relative to FIG. 4); the values of T₂ relaxation times (e.g.,0.1 ms≤¹H T₂<300 ms); the values of T₁/T₂ ratios (e.g., 1<¹H T₁/T₂≤100);the area under an extrapolation of a T₂ NMR signal intensity (e.g., asdescribed relative to FIG. 3); the area under a T₁-T₂ relaxation timeplot; the T₂ and T₁-relaxation corrected signals within the spatialboundaries of the core sample; and the like; and any combinationthereof.

For example, a method of the present disclosure for assessing fluidmobility in a core sample can include determining a porosity of a coresample, wherein the core sample has a permeability of 100 mD or less;saturating the core sample with a NMR saturation fluid; taking a firstNMR measurement of fluid in the core sample; hydraulically exchanging ahydrophobic fluid or a hydrophilic fluid in the core sample in ahydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity, a NMR signal to fluid volume calibration, and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable oil volume, an irreduciblehydrocarbon volume, and any combination thereof when using thehydrophilic NMR exchange fluid or is selected from the second groupconsisting of a recoverable water volume, an irreducible water volume,and any combination thereof when using the hydrophobic NMR exchangefluid; and optionally, repeating the hydraulic exchange with the otherof the hydrophobic fluid or the hydrophilic fluid and taking a third NMRmeasurement and deriving the property of the first or second group,wherein the NMR measurements are ¹H T₂ relaxation times measured withlow-field and/or intermediate-field NMR and the comparison is a changein an area under a ¹H T₂ relaxation time spectrum of the core samplefrom 0.1 ms to 300 ms.

In another example, a method of the present disclosure for assessingfluid mobility in a core sample can include determining a porosity of acore sample, wherein the core sample has a permeability of 100 mD orless; saturating the core sample with a NMR saturation fluid; taking afirst NMR measurement of fluid in the core sample; hydraulicallyexchanging a hydrophobic fluid or a hydrophilic fluid in the core samplein a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity, a NMR signal to fluid volume calibration, and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable oil volume, an irreduciblehydrocarbon volume, and any combination thereof when using thehydrophilic NMR exchange fluid or is selected from the second groupconsisting of a recoverable water volume, an irreducible water volume,and any combination thereof when using the hydrophobic NMR exchangefluid; and optionally, repeating the hydraulic exchange with the otherof the hydrophobic fluid or the hydrophilic fluid and taking a third NMRmeasurement and deriving the property of the first or second group,wherein the NMR measurements are ¹H T₁-T₂ 2-dimensional correlation mapmeasured with low-field and/or intermediate-field NMR and the comparisonis a change in an area under a ¹H T₁-T₂ relaxation time plot of fluid inthe core sample from T₂ of 0.1 ms to 300 ms and T₁ of 0.1 ms to 300 msand the NMR signal to fluid volume calibration.

In yet another example, a method of the present disclosure for assessingfluid mobility in a core sample can include determining a porosity of acore sample, wherein the core sample has a permeability of 100 mD orless; saturating the core sample with a NMR saturation fluid; taking afirst NMR measurement of fluid in the core sample; hydraulicallyexchanging a hydrophobic fluid or a hydrophilic fluid in the core samplein a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity, a NMR signal to fluid volume calibration, and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable oil volume, an irreduciblehydrocarbon volume, and any combination thereof when using thehydrophilic NMR exchange fluid or is selected from the second groupconsisting of a recoverable water volume, an irreducible water volume,and any combination thereof when using the hydrophobic NMR exchangefluid; and optionally, repeating the hydraulic exchange with the otherof the hydrophobic fluid or the hydrophilic fluid and taking a third NMRmeasurement and deriving the property of the first or second group,wherein the NMR measurements are ¹H T₁/T₂ ratio measured with low-fieldand/or intermediate-field NMR and the comparison is a change in an areaan area under a ¹H T₁/T₂ ratio of 1<¹H T₁/T₂ ratio≤100 of a fluid in thecore sample.

In another example, a method of the present disclosure for assessingfluid mobility in a core sample can include determining a porosity of acore sample, wherein the core sample has a permeability of 100 mD orless; saturating the core sample with a NMR saturation fluid; taking afirst NMR measurement of fluid in the core sample; hydraulicallyexchanging a hydrophobic fluid or a hydrophilic fluid in the core samplein a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity, a NMR signal to fluid volume calibration, and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable oil volume, an irreduciblehydrocarbon volume, and any combination thereof when using thehydrophilic NMR exchange fluid or is selected from the second groupconsisting of a recoverable water volume, an irreducible water volume,and any combination thereof when using the hydrophobic NMR exchangefluid; and optionally, repeating the hydraulic exchange with the otherof the hydrophobic fluid or the hydrophilic fluid and taking a third NMRmeasurement and deriving the property of the first or second group,wherein the NMR measurements are T₂ NMR signal intensity as a functionof refocusing delay and the comparison is in a y-value at a y-interceptof an extrapolation of the T₂ NMR signal intensity including x=0.

In yet another example, a method of the present disclosure for assessingfluid mobility in a core sample can include determining a porosity of acore sample, wherein the core sample has a permeability of 100 mD orless; saturating the core sample with a NMR saturation fluid; taking afirst NMR measurement of fluid in the core sample; hydraulicallyexchanging a hydrophobic fluid or a hydrophilic fluid in the core samplein a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity, a NMR signal to fluid volume calibration, and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable oil volume, an irreduciblehydrocarbon volume, and any combination thereof when using thehydrophilic NMR exchange fluid or is selected from the second groupconsisting of a recoverable water volume, an irreducible water volume,and any combination thereof when using the hydrophobic NMR exchangefluid; and optionally, repeating the hydraulic exchange with the otherof the hydrophobic fluid or the hydrophilic fluid and taking a third NMRmeasurement and deriving the property of the first or second group,wherein the NMR measurements are ¹H spectroscopy measured withhigh-field NMR and the comparison is a change in an area under a ¹Hspectrum of a fluid in the core sample from 10 ppm to 0 ppm.

In another example, a method of the present disclosure for assessingfluid mobility in a core sample can include determining a porosity of acore sample, wherein the core sample has a permeability of 100 mD orless; saturating the core sample with a NMR saturation fluid; taking afirst NMR measurement of fluid in the core sample; hydraulicallyexchanging a hydrophobic fluid or a hydrophilic fluid in the core samplein a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity, a NMR signal to fluid volume calibration, and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable oil volume, an irreduciblehydrocarbon volume, and any combination thereof when using thehydrophilic NMR exchange fluid or is selected from the second groupconsisting of a recoverable water volume, an irreducible water volume,and any combination thereof when using the hydrophobic NMR exchangefluid; and optionally, repeating the hydraulic exchange with the otherof the hydrophobic fluid or the hydrophilic fluid and taking a third NMRmeasurement and deriving the property of the first or second group,wherein the NMR measurements are imaging measured withintermediate-field and/or high-field NMR the comparison is a change in aT₂- and T₁-relaxation corrected signal for a fluid within spatialboundaries of the core sample and the NMR signal to fluid volumecalibration.

Further, the NMR measurements can be used to identify which pore typesthe fluids being forced from and the amount of said fluids by pore type.Said NMR measurements can be those described for pore types, whichinclude, but are not limited to, the values of T₂ relaxation times(e.g., ¹H T₂ values of Table 1); the values of T₁/T₂ ratios (e.g., ¹HT₁/T₂ ratios of Table 2); T₂ signal intensity as a function ofrefocusing delay; the T₂ and Ti-relaxation corrected signals within thespatial boundaries of the core sample; and the like; and any combinationthereof. Accordingly, one or more of the following can be determined: arecoverable nanopore oil volume, a recoverable micropore oil volume, arecoverable macropore oil volume, a recoverable nanopore water volume, arecoverable micropore water volume, a recoverable macropore watervolume, an irreducible nanopore hydrocarbon volume, an irreduciblemicropore hydrocarbon volume, an irreducible macropore hydrocarbonvolume, an irreducible nanopore water volume, an irreducible microporewater volume, an irreducible macropore water volume, an immobilenanopore volume, an immobile micropore volume, an immobile macroporevolume, and any combination thereof

For example, the NMR measurements can be ¹H T₂ relaxation times wherethe reduction of T₂ signal intensity for over T₂ relaxation time rangesper Table 1 can be used to identify a volume of recoverable water ineach pore type (when a hydrophobic NMR exchange fluid is used) and/oridentify a volume of recoverable hydrocarbon in each pore type (when ahydrophilic NMR exchange fluid is used).

Accordingly, a method of the present disclosure for determining themobility of fluids in different pore types can include determining aporosity of a core sample, wherein the core sample has a permeability ofmD or less; saturating the core sample with a NMR saturation fluid toachieve a saturated core sample; taking a first NMR measurement of thefluid in the saturated core sample; hydraulically exchanging ahydrophobic fluid or a hydrophilic fluid in the core sample in ahydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity and a comparison between the first NMR measurementand the second NMR measurement, wherein the property of the core sampleis selected from the first group consisting of a recoverable nanoporeoil volume, a recoverable micropore oil volume, a recoverable macroporeoil volume, an irreducible nanopore hydrocarbon volume, an irreduciblemicropore hydrocarbon volume, an irreducible macropore hydrocarbonvolume, and any combination thereof for the hydrophilic NMR exchangefluid or is selected from the second group consisting of a recoverablenanopore water volume, a recoverable micropore water volume, arecoverable macropore water volume, an irreducible nanopore watervolume, an irreducible micropore water volume, an irreducible macroporewater volume, and any combination thereof for the hydrophobic NMRexchange fluid. and optionally, repeating the hydraulic exchange withthe other of the hydrophobic fluid or the hydrophilic fluid and taking athird NMR measurement for comparison to the second NMR measurement todetermine the first or second group of properties, wherein the NMRmeasurement is ¹H T₂ relaxation times measured with low-field and/orintermediate-field NMR and the comparison is a change in an area under a¹H T₂ relaxation time spectrum for one selected from the groupconsisting of 0.1 ms≤T₂<1.5 ms for the nanopore volumes, 1.5 ms≤T₂ <30ms for the micropore volumes, 30 ms≤T₂<300 ms for the macropore volumes,and any combination thereof.

In another example, a method of the present disclosure for determiningthe mobility of fluids in different pore types can include determining aporosity of a core sample, wherein the core sample has a permeability ofmD or less; saturating the core sample with a NMR saturation fluid toachieve a saturated core sample; taking a first NMR measurement of thefluid in the saturated core sample; hydraulically exchanging ahydrophobic fluid or a hydrophilic fluid in the core sample in ahydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity and a comparison between the first NMR measurementand the second NMR measurement, wherein the property of the core sampleis selected from the first group consisting of a recoverable nanoporeoil volume, a recoverable micropore oil volume, a recoverable macroporeoil volume, an irreducible nanopore hydrocarbon volume, an irreduciblemicropore hydrocarbon volume, an irreducible macropore hydrocarbonvolume, and any combination thereof for the hydrophilic NMR exchangefluid or is selected from the second group consisting of a recoverablenanopore water volume, a recoverable micropore water volume, arecoverable macropore water volume, an irreducible nanopore watervolume, an irreducible micropore water volume, an irreducible macroporewater volume, and any combination thereof for the hydrophobic NMRexchange fluid. and optionally, repeating the hydraulic exchange withthe other of the hydrophobic fluid or the hydrophilic fluid and taking athird NMR measurement for comparison to the second NMR measurement todetermine the first or second group of properties, wherein the NMRmeasurement is ¹H T₁-T₂ 2-dimensional correlation map measured withlow-field and/or intermediate-field NMR and the comparison a change inan area under the ¹H T₁-T₂ 2-dimensional correlation map for oneselected from the group consisting of 0.1 ms≤T₂<1.5 ms for the nanoporevolumes, 1.5 ms≤T₂<30 ms for the micropore volumes, 30 ms≤T₂<300 ms forthe macropore volumes, and any combination thereof.

In yet another example, a method of the present disclosure fordetermining the mobility of fluids in different pore types can includedetermining a porosity of a core sample, wherein the core sample has apermeability of mD or less; saturating the core sample with a NMRsaturation fluid to achieve a saturated core sample; taking a first NMRmeasurement of the fluid in the saturated core sample; hydraulicallyexchanging a hydrophobic fluid or a hydrophilic fluid in the core samplein a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity and a comparison between the first NMR measurementand the second NMR measurement, wherein the property of the core sampleis selected from the first group consisting of a recoverable nanoporeoil volume, a recoverable micropore oil volume, a recoverable macroporeoil volume, an irreducible nanopore hydrocarbon volume, an irreduciblemicropore hydrocarbon volume, an irreducible macropore hydrocarbonvolume, and any combination thereof for the hydrophilic NMR exchangefluid or is selected from the second group consisting of a recoverablenanopore water volume, a recoverable micropore water volume, arecoverable macropore water volume, an irreducible nanopore watervolume, an irreducible micropore water volume, an irreducible macroporewater volume, and any combination thereof for the hydrophobic NMRexchange fluid. and optionally, repeating the hydraulic exchange withthe other of the hydrophobic fluid or the hydrophilic fluid and taking athird NMR measurement for comparison to the second NMR measurement todetermine the first or second group of properties, wherein the NMRmeasurement is T₂-weighted imaging and the comparison is for a change ina T₂- and T₁-relaxation corrected signal for the fluids within spatialboundaries of the core sample where the T₂-weight is 0.1 ms≤T₂<1.5 msfor the nanopore volumes, where the T₂-weight is 1.5 ms≤T₂<30 ms for themicropore volumes, and where the T₂-weight is for 30 ms≤T₂<300 ms forthe macropore volumes.

In another example, a method of the present disclosure for determiningthe mobility of fluids in different pore types can include determining aporosity of a core sample, wherein the core sample has a permeability ofmD or less; saturating the core sample with a NMR saturation fluid toachieve a saturated core sample; taking a first NMR measurement of thefluid in the saturated core sample; hydraulically exchanging ahydrophobic fluid or a hydrophilic fluid in the core sample in ahydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity and a comparison between the first NMR measurementand the second NMR measurement, wherein the property of the core sampleis selected from the first group consisting of a recoverable nanoporeoil volume, a recoverable micropore oil volume, a recoverable macroporeoil volume, an irreducible nanopore hydrocarbon volume, an irreduciblemicropore hydrocarbon volume, an irreducible macropore hydrocarbonvolume, and any combination thereof for the hydrophilic NMR exchangefluid or is selected from the second group consisting of a recoverablenanopore water volume, a recoverable micropore water volume, arecoverable macropore water volume, an irreducible nanopore watervolume, an irreducible micropore water volume, an irreducible macroporewater volume, and any combination thereof for the hydrophobic NMRexchange fluid. and optionally, repeating the hydraulic exchange withthe other of the hydrophobic fluid or the hydrophilic fluid and taking athird NMR measurement for comparison to the second NMR measurement todetermine the first or second group of properties, wherein the NMRmeasurement is a ¹H T₁/T₂ ratio measured with low-field and/orintermediate-field NMR and the comparison is a change in the ¹H T₁/T₂ratio for one selected from the group consisting of 10≤¹H T₁/T₂<100 forthe nanopore volumes, 3≤¹H T₁/T₂<10 for the micropore volumes, 1≤¹HT₁/T₂<3 for the macropore volumes, and any combination thereof

In yet another example, a method of the present disclosure fordetermining the mobility of fluids in different pore types can includedetermining a porosity of a core sample, wherein the core sample has apermeability of mD or less; saturating the core sample with a NMRsaturation fluid to achieve a saturated core sample; taking a first NMRmeasurement of the fluid in the saturated core sample; hydraulicallyexchanging a hydrophobic fluid or a hydrophilic fluid in the core samplein a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity and a comparison between the first NMR measurementand the second NMR measurement, wherein the property of the core sampleis selected from the first group consisting of a recoverable nanoporeoil volume, a recoverable micropore oil volume, a recoverable macroporeoil volume, an irreducible nanopore hydrocarbon volume, an irreduciblemicropore hydrocarbon volume, an irreducible macropore hydrocarbonvolume, and any combination thereof for the hydrophilic NMR exchangefluid or is selected from the second group consisting of a recoverablenanopore water volume, a recoverable micropore water volume, arecoverable macropore water volume, an irreducible nanopore watervolume, an irreducible micropore water volume, an irreducible macroporewater volume, and any combination thereof for the hydrophobic NMRexchange fluid. and optionally, repeating the hydraulic exchange withthe other of the hydrophobic fluid or the hydrophilic fluid and taking athird NMR measurement for comparison to the second NMR measurement todetermine the first or second group of properties, wherein the NMRmeasurement is T₂ NMR signal intensity as a function of refocusing delayand the comparison a change in a multi-exponential fit of the T₂ NMRsignal intensity as a function of refocusing delay where a slope of eachexponential factor in the multi-exponential fit relates to a pore typeand a pre-exponential factor of each exponential factor in themulti-exponential fit relates to a volume of the pore type.

In another example, a method of the present disclosure for determiningthe mobility of fluids in different pore types can include determining aporosity of a core sample, wherein the core sample has a permeability ofmD or less; saturating the core sample with a NMR saturation fluid toachieve a saturated core sample; taking a first NMR measurement of thefluid in the saturated core sample; hydraulically exchanging ahydrophobic fluid or a hydrophilic fluid in the core sample in ahydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity and a comparison between the first NMR measurementand the second NMR measurement, wherein the property of the core sampleis selected from the first group consisting of a recoverable nanoporeoil volume, a recoverable micropore oil volume, a recoverable macroporeoil volume, an irreducible nanopore hydrocarbon volume, an irreduciblemicropore hydrocarbon volume, an irreducible macropore hydrocarbonvolume, and any combination thereof for the hydrophilic NMR exchangefluid or is selected from the second group consisting of a recoverablenanopore water volume, a recoverable micropore water volume, arecoverable macropore water volume, an irreducible nanopore watervolume, an irreducible micropore water volume, an irreducible macroporewater volume, and any combination thereof for the hydrophobic NMRexchange fluid. and optionally, repeating the hydraulic exchange withthe other of the hydrophobic fluid or the hydrophilic fluid and taking athird NMR measurement for comparison to the second NMR measurement todetermine the first or second group of properties, wherein the NMRmeasurement is diffusometry and the comparison is a change a T₂- andT₁-relaxation corrected area under a diffusion spectrum of the fluids inthe core sample for 1×10⁻¹⁴ m²/s<diffusion rate≤1×10⁻¹¹ m²/s fornanopore volumes and/or for 1×10⁻¹¹ m²/s <diffusion rate−1×10⁻⁹ m²/s formicropore volumes.

Calibrating NMR Logs

One or more of the core sample attributes described herein (e.g.,porosity, pore type distribution, nanopore oil volume, nanopore watervolume, micropore oil volume, micropore water volume, macropore oilvolume, macropore water volume, oil saturation volume, water saturationvolume, recoverable oil volume, recoverable water volume, irreducibleoil volume, irreducible water volume, and immobile fluid volume,described further herein) can be used to calibrate a NMR log of awellbore. For example, one or more core samples taken from knownlocations along a wellbore can be analyzed for one or more core sampleattributes. Further, a NMR log of the wellbore can be measured.Measurements of T₂ and Ti relaxation as well as fluid mobility andcombinations thereof provide properties of the fluid and the reservoir.Then, the locations along the wellbore where the core samples and NMRlog correspond can be identified. At those locations, the NMR log signalor properties derived therefrom (e.g., porosity, mobile oil, mobilewater, and the like) can be corrected to match the measurements and/oranalyses of the core samples.

In a nonlimiting example, the NMR log can be used to derive a formationporosity as a function of length of the wellbore. Then, for example, theNMR log-derived formation porosity can be compared to the coresample-derived porosity at locations along the wellbore where the coresamples were taken. If the two porosities are within a threshold (e.g.,about 5%) for some minimum number of location then the NMR log-derivedformation porosity may be considered within calibration. However, whenoutside a threshold at some minimum number of locations, then using someor all of the locations, a calibration factor or equation can be derivedand applied to the NMR log-derived formation porosity to bring themwithin the threshold.

The number of core samples analyzed as a function of distance along thewellbore is dependent number of strata within the formation and thedesired level of quality for the calibration. By way of nonlimitingexample, 2-3 core samples per strata may provide a balance between cost(retrieval of core samples and subsequent analysis) and time andaccuracy. However, as few as 1 or as many as 50 or more core samples canbe taken from the strata of interest.

Artificial NMR Logs

One or more of the core sample attributes described herein (e.g.,porosity, pore type distribution, nanopore oil volume, nanopore watervolume, micropore oil volume, micropore water volume, macropore oilvolume, macropore water volume, oil saturation volume, water saturationvolume, recoverable oil volume, recoverable water volume, irreducibleoil volume, irreducible water volume, and immobile fluid volume,described further herein) can be used to produce an artificial NMR log.Here, a plurality of core samples are extracted from the formation andanalyzed for one or more of the core sample attributes. The results canbe plotted as the core sample attribute as a function of length alongthe wellbore. Then, trendlines or other modeling algorithms can be usedto estimate the formation properties (or a range of formationproperties) between the core sample attribute data points. The resultantplot is an artificial NMR log. Since many of the core sample attributesdescribed herein are not measureable by conventional NMR loggingtechniques, these artificial NMR logs can provide additional valuableinformation to engineers as drilling, enhanced oil recovery, andproduction strategies are developed.

Any number of core samples (e.g., 2 to 100 core samples) can be used toproduce artificial NMR logs. Typically, when core samples are taken, asingle trip downhole can yield 10 to 20 sidewall core samples and/or 1to 5 vertical core samples. Generally, 6 to 10 core samples per 2000 ftof wellbore is suitable for producing artificial NMR logs. Although moreor less core samples could also be used.

Exemplary Embodiments

A first nonlimiting exemplary embodiment is a method comprising:saturating a core sample with a NMR saturation fluid, wherein the coresample has a permeability of 100 mD or less, to achieve a saturated coresample; taking a NMR measurement of fluids in the saturated core sample;determining a porosity of the core sample based on a correlation betweenthe NMR measurement and a NMR signal to fluid volume calibration. Such amethod may include one or more of the following: Element 1: wherein theNMR measurement is ¹H spectroscopy measured with high-field NMR and thecorrelation is between an area under a ¹H spectrum from 10 ppm to 0 ppmand the NMR signal to fluid volume calibration.; Element 2: wherein theNMR measurement is ¹H T₁/T₂ ratio measured with low-field and/orintermediate-field NMR and the correlation is between an area under a ¹HT₁/T₂ ratio of 1<¹H T₁/T₂ ratio≤100 and the NMR signal to fluid volumecalibration; Element 3: wherein the NMR measurement is T₂ NMR signalintensity as a function of refocusing delay and the correlation isbetween a y-value at a y-intercept of an extrapolation of the T₂ NMRsignal intensity including x=0 and the NMR signal to fluid volumecalibration; Element 4: wherein the NMR measurement is ¹H T₂ relaxationtimes measured with low-field and/or intermediate-field NMR and thecorrelation is between an area under a ¹H T₂ relaxation time spectrumfrom 0.1 ms to 300 ms and the NMR signal to fluid volume calibration;Element 5: wherein the NMR measurement is ¹H T₁-T₂ 2-dimensionalcorrelation map measured with low-field and/or intermediate-field NMRand the correlation is between an area under a ¹H T₁-T₂ relaxation timeplot from T₂ of 0.1 ms to 300 ms and T, of 0.1 ms to 300 ms and the NMRsignal to fluid volume calibration; Element 6: wherein the NMRmeasurement is imaging measured with intermediate-field and/orhigh-field NMR and the correlation is between a T₂- and T₁-relaxationcorrected signal for the fluids within spatial boundaries of the coresample and the NMR signal to fluid volume calibration; Element 7:wherein the NMR saturation fluid is hydrophilic; Element 8: wherein theNMR saturation fluid is hydrophobic; Element 9: wherein the NMRsaturation fluid comprises dodecane; Element 10: wherein the NMRsaturation fluid comprises a mixture of synthetic paraffins; Element 11:the method further comprising: taking a mass of the core sample beforeand after saturating; Element 12: the method further comprising:deriving a core sample property based on at least the porosity and theNMR measurement, wherein the core sample property is one or moreselected from the group consisting of: a pore type distribution, ananopore oil volume, a nanopore water volume, a micropore oil volume, amicropore water volume, a macropore oil volume, and a macropore watervolume.; Element 13: Element 12 and the method further comprising:performing the method for a plurality of core samples; corresponding thecore sample properties to the lengths along a wellbore from which thecorresponding core samples were taken; and estimating a formationproperty corresponding to the core sample property at lengths along thewellbore between where the plurality of core samples were taken; Element14: wherein the NMR measurement is a first NMR measurement; and themethod further comprising: hydraulically exchanging a fluid in the coresample with a NMR exchange fluid; taking a second NMR measurement of thecore sample after hydraulic exchange; and deriving a core sampleproperty based on at least the porosity and a comparison between thefirst NMR measurement and the second NMR measurement, wherein the coresample property is one or more selected from the group consisting of: arecoverable oil volume, a recoverable water volume, an irreduciblehydrocarbon volume, an irreducible water volume, and an immobile fluidvolume; Element 15: Element 14 and the method further comprising: takinga mass of the core sample before and after hydraulic exchange; Element16: Element 14 (and optionally Element 15) and the method furthercomprising: performing the method for a plurality of core samples;corresponding the core sample properties to the lengths along a wellborefrom which the corresponding core samples were taken; and estimating aformation property corresponding to the core sample property at lengthsalong the wellbore between where the plurality of core samples weretaken; Element 17: the method further comprising: providing a NMR loghaving porosity data of a wellbore from which the core sample wasextracted; and calibrating the porosity data of the NMR log based on acomparison of the porosity data at a corresponding length along thewellbore to the porosity of the core sample; and Element 18: the methodfurther comprising: performing the method for a plurality of coresamples; corresponding the porosities to the lengths along a wellborefrom which the corresponding core samples were taken; and estimating aformation porosity at lengths along the wellbore between where theplurality of core samples were taken to produce an artificial NMR log.Examples of combinations of elements can include, but are not limitedto, two or more of Elements 1-6 in combination; Element 7 or Element 8(and optionally Element 9 and/or Element 10) in combination with one ormore of Elements 1-6; Element 7 or Element 8 (and optionally Element 9and/or Element 10) in combination with one or more of Elements 11-18 andoptionally in further combination with one or more of Elements 1-6; oneor more of Elements 1-6 in combination with one or more of Elements11-18; two or more of Elements 11-18 in combination; and Element 8 incombination with one or both of Elements 9-10.

A second nonlimiting exemplary embodiment of the present disclosure is amethod comprising: determining a porosity of a core sample, wherein thecore sample has a permeability of 100 mD or less; saturating the coresample with a NMR saturation fluid to achieve a saturated core sample;taking a NMR measurement of fluids in the saturated core sample; andderiving a volume for a pore type based on the porosity based on acorrelation between the NMR measurement and a NMR signal to fluid volumecalibration, wherein the pore type is selected from the group consistingof a nanopore, a micropore, a macropore, and any combination thereof.Optionally, determining the porosity of the core sample can be via thefirst nonlimiting example embodiment and optionally one or more ofElements 1-18. The second nonlimiting example embodiment (optionallyincluding the first nonlimiting example embodiment) may include one ormore of the following: Element 7, Element 8, Element 9, Element 10,Element 11; Element 19: wherein the NMR measurement is ¹H T₁/T₂ ratiomeasured with low-field and/or intermediate-field NMR and thecorrelation is between the NMR signal to fluid volume calibration andthe ¹H T₁/T₂ ratio for one selected from the group consisting of 10≤¹HT₁/T₂<100 for the nanopores, 3≤¹H T₁/T₂<10 for the micropores, 1≤¹HT₁/T₂<3 for the macropores, and any combination thereof; Element 20:wherein the NMR measurement is T₂ NMR signal intensity as a function ofrefocusing delay and the correlation is between the NMR signal to fluidvolume calibration and a multi-exponential fit of the T₂ NMR signalintensity as a function of refocusing delay where a slope of eachexponential factor in the multi-exponential fit relates to the pore typeand a pre-exponential factor of each exponential factor in themulti-exponential fit relates to the volume of the pore type; Element21: wherein the NMR measurement is ¹H T₂ relaxation times measured withlow-field and/or intermediate-field NMR and the correlation is betweenthe NMR signal to fluid volume calibration and an area under a ¹H T₂relaxation time spectrum for one selected from the group consisting of0.1 ms≤T₂<1.5 ms for the nanopores, 1.5 ms≤T₂<30 ms for the micropores,30 ms≤T₂<300 ms for the macropores, and any combination thereof; Element22: wherein the NMR measurement is ¹H T₁-T₂ 2-dimensional correlationmap measured with low-field and/or intermediate-field NMR and thecorrelation is between the NMR signal to fluid volume calibration and anarea under the ¹H T₁-T₂ 2-dimensional correlation map for one selectedfrom the group consisting of 0.1 ms≤T₂<1.5 ms for the nanopores, 1.5ms≤T₂<30 ms for the micropores, 30 ms≤T₂<300 ms for the macropores, andany combination thereof; Element 23: wherein the NMR measurement isdiffusometry and the correlation is between the NMR signal to fluidvolume calibration and a T₂- and T₁-relaxation corrected area under adiffusion spectrum for 1×10⁻¹⁴ m²/s<diffusion rate≤1×10⁻¹¹ m²/s fornanopores and/or for 1×10⁻¹¹ m²/s<diffusion rate≤1×10⁻⁹ m²/s formicropores; Element 24: wherein the NMR measurement is T₂-weightedimaging and the correlation is between the NMR signal to fluid volumecalibration and a T₂- and T₁-relaxation corrected signal for the fluidswithin spatial boundaries of the core sample where the T₂-weight is 0.1ms≤T₂<1.5 ms for the nanopores, where the T₂-weight is 1.5 ms≤T₂<30 msfor the micropores, and where the T₂-weight is for 30 ms≤T₂<300 ms forthe macropores; and Element 25: the method further comprising:performing the method for a plurality of core samples; corresponding thepore type to the lengths along a wellbore from which the correspondingcore samples were taken; and estimating a formation pore type at lengthsalong the wellbore between where the plurality of core samples weretaken to produce an artificial NMR log. Examples of combinations ofelements include, but are not limited to, two or more of Elements 7-11in combination; two or more of Elements 19-24 in combination; Element 25in combination with one or more of Elements 19-24 and optionally infurther combination with one or more of Elements 7-11; Element 25 incombination with one or more of Elements 7-11; and one or more ofElements 19-24 in combination with one or more of Elements 7-11.

A third nonlimiting exemplary embodiment of the present disclosure is amethod comprising: determining a porosity of a core sample, wherein thecore sample has a permeability of 100 mD or less; saturating the coresample with a NMR measurement saturation fluid to achieve a saturatedcore sample; taking a first NMR measurement of fluids in the saturatedcore sample; hydraulically exchanging a hydrophobic fluid or ahydrophilic fluid in the core sample in a hydrophilic NMR exchange fluidor a hydrophobic NMR exchange fluid, respectively; taking a second NMRmeasurement of the fluids in the core sample after hydraulic exchange;deriving a property of the core sample based on the porosity and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable nanopore oil volume, arecoverable micropore oil volume, a recoverable macropore oil volume, anirreducible nanopore hydrocarbon volume, an irreducible microporehydrocarbon volume, an irreducible macropore hydrocarbon volume, and anycombination thereof for the hydrophilic NMR exchange fluid or isselected from the second group consisting of a recoverable nanoporewater volume, a recoverable micropore water volume, a recoverablemacropore water volume, an irreducible nanopore water volume, anirreducible micropore water volume, an irreducible macropore watervolume, and any combination thereof for the hydrophobic NMR exchangefluid. Optionally, determining the porosity of the core sample can bevia the first nonlimiting example embodiment and optionally one or moreof Elements 1-18. The third nonlimiting example embodiment (optionallyincluding the first nonlimiting example embodiment) may include one ormore of the following: Element 7, Element 8, Element 9, Element 10,Element 11; Element 26: wherein the NMR measurement is a ¹H T₁/T₂ ratiomeasured with low-field and/or intermediate-field NMR and the comparisonis a change in the ¹H T₁/T₂ ratio for one selected from the groupconsisting of 10≤¹H T₁/T₂<100 for the nanopore volumes, 3≤¹H T₁/T₂<10for the micropore volumes, 1≤¹H T₁/T₂<3 for the macropore volumes, andany combination thereof; Element 27: method of claim B13, wherein theNMR measurement is T₂ NMR signal intensity as a function of refocusingdelay and the comparison a change in a multi-exponential fit of the T₂NMR signal intensity as a function of refocusing delay where a slope ofeach exponential factor in the multi-exponential fit relates to a poretype and a pre-exponential factor of each exponential factor in themulti-exponential fit relates to a volume of the pore type; Element 28:wherein the NMR measurement is ¹H T₂ relaxation times measured withlow-field and/or intermediate-field NMR and the comparison is a changein an area under a ¹H T₂ relaxation time spectrum for one selected fromthe group consisting of 0.1 ms≤T₂<1.5 ms for the nanopore volumes, 1.5ms≤T₂<30 ms for the micropore volumes, 30 ms≤T₂<300 ms for the macroporevolumes, and any combination thereof; Element 29: wherein the NMRmeasurement is ¹H T₁-T₂ 2-dimensional correlation map measured withlow-field and/or intermediate-field NMR and the comparison a change inan area under the ¹H T₁-T₂ 2-dimensional correlation map for oneselected from the group consisting of 0.1 ms≤T₂<1.5 ms for the nanoporevolumes, 1.5 ms≤T₂<30 ms for the micropore volumes, 30 ms≤T₂<300 ms forthe macropore volumes, and any combination thereof; Element 30: whereinthe NMR measurement is diffusometry and the comparison is a change in aT₂- and T₁-relaxation corrected area under a diffusion spectrum for1×10⁻¹⁴ m²/s<diffusion rate <1×10-¹¹ m²/s for nanopore volumes and/orfor 1×10⁻¹¹ m²/s<diffusion rate≤1×10⁻⁹ m²/s for micropore volumes;Element 31: wherein the NMR measurement is T₂-weighted imaging and thecomparison is for a change in a T₂- and T₁-relaxation corrected signalfor the fluids within spatial boundaries of the core sample where theT₂-weight is 0.1 ms≤T₂<1.5 ms for the nanopore volumes, where theT₂-weight is 1.5 ms≤T₂<30 ms for the micropore volumes, and where theT₂-weight is for 30 ms≤T₂<300 ms for the macropore volumes; Element 32:wherein the hydrophilic NMR exchange fluid comprises water; Element 33:wherein the hydrophobic NMR exchange fluid comprises a mixture ofsynthetic paraffins; Element 34: wherein the hydrophobic NMR exchangefluid comprises dodecane; Element 35: the method further comprising:taking a mass of the core sample before and after hydraulic exchange;Element 36: the method further comprising: performing compositionalanalysis on fluids that elutes from the core sample during hydraulicexchange; Element 37: wherein the hydrophobic NMR exchange fluid ishydraulically exchanged for the hydrophilic fluid in the core sample;Element 38: Element 37 and the method further comprising: hydraulicallyexchanging the hydrophilic fluid in the core sample and the hydrophobicNMR exchange fluid; taking a third NMR measurement of the fluids in thecore sample after the second hydraulic exchange; and deriving a secondproperty of the core sample based on the porosity and a comparisonbetween the second NMR measurement and the third NMR measurement,wherein the property of the core sample is selected from the groupconsisting of the recoverable nanopore water volume, the recoverablemicropore water volume, the recoverable macropore water volume, theirreducible nanopore water volume, the irreducible micropore watervolume, the irreducible macropore water volume, an immobile nanoporevolume, an immobile micropore volume, an immobile macropore volume, andany combination thereof; Element 39: wherein the hydrophilic NMRexchange fluid is hydraulically exchanged for the hydrophobic fluid inthe core sample; Element 40: Element 39 and the method furthercomprising: hydraulically exchanging the hydrophobic fluid in the coresample and the hydrophilic NMR exchange fluid; taking a third NMRmeasurement of the fluids in the core sample after the second hydraulicexchange; and deriving a second property of the core sample based on theporosity and a comparison between the second NMR measurement and thethird NMR measurement, wherein the property of the core sample isselected from the first group consisting of the recoverable nanopore oilvolume, the recoverable micropore oil volume, the recoverable macroporeoil volume, the irreducible nanopore hydrocarbon volume, the irreduciblemicropore hydrocarbon volume, the irreducible macropore hydrocarbonvolume, an immobile nanopore volume, an immobile micropore volume, animmobile macropore volume, and any combination thereof; and Element 41:the method further comprising: performing the method for a plurality ofcore samples; corresponding the pore type to the lengths along awellbore from which the corresponding core samples were taken; andestimating the first property and optionally the second property atlengths along the wellbore between where the plurality of core sampleswere taken to produce an artificial NMR log. Examples of combinationscan include, but are not limited to, two or more of Elements 26-31 incombination; one or more of Elements 26-31 in combination with one ormore of Elements 32-41; one or more of Elements 32-34 (optionally incombination with one or more of Elements 35, 36, and 41) in combinationwith Element 37 (and optionally Element 38) or with Element 39 (andoptionally Element 40); one of Elements; one or more of Elements 35, 36,and 41 in combination with one or more of Elements 32-34; and one ormore of Elements 35, 36, and 41 in combination with Element 37 (andoptionally Element 38) or with Element 39 (and optionally Element 40);and one or more of Elements 7-11 in combination with one or more ofElements 26-41.

A fourth nonlimiting exemplary embodiment is a method comprising:determining a porosity of a core sample, wherein the core sample has apermeability of 100 mD or less; saturating the core sample with a NMRsaturation fluid; taking a first NMR measurement of fluids in the coresample; hydraulically exchanging a hydrophobic fluid or a hydrophilicfluid in the core sample in a hydrophilic NMR exchange fluid or ahydrophobic NMR exchange fluid, respectively; taking a second NMRmeasurement of the fluids in the core sample after hydraulic exchange;and deriving a property of the core sample based on the porosity, a NMRsignal to fluid volume calibration, and a comparison between the firstNMR measurement and the second NMR measurement, wherein the property ofthe core sample is selected from the first group consisting of arecoverable oil volume, an irreducible hydrocarbon volume, and anycombination thereof when using the hydrophilic NMR exchange fluid or isselected from the second group consisting of a recoverable water volume,an irreducible water volume, and any combination thereof when using thehydrophobic NMR exchange fluid. Optionally, determining the porosity ofthe core sample can be via the first nonlimiting example embodiment andoptionally one or more of Elements 1-18. The fourth nonlimiting exampleembodiment (optionally including the first nonlimiting exampleembodiment) may include one or more of the following: Element 7; Element8; Element 9; Element 10; Element 11; Element 32; Element 33; Element34; Element 35; Element 36; Element 42: wherein the NMR measurements are¹H spectroscopy measured with high-field NMR and the comparison is achange in an area under a ¹H spectrum from 10 ppm to 0 ppm; Element 43:wherein the NMR measurements are ¹H T₁/T₂ ratio measured with low-fieldand/or intermediate-field NMR and the comparison is a change in an areaan area under a ¹H T₁/T₂ ratio of 1<¹H T₁/T₂ ratio≤100; Element 44:wherein the NMR measurements are T₂ NMR signal intensity as a functionof refocusing delay and the comparison is in a y-value at a y-interceptof an extrapolation of the T₂ NMR signal intensity including x=0;Element 45: wherein the NMR measurements are ¹H T₂ relaxation timesmeasured with low-field and/or intermediate-field NMR and the comparisonis a change in an area under a ¹H T₂ relaxation time spectrum from 0.1ms to 300 ms; Element 46: wherein the NMR measurements are ¹H T₁-T₂2-dimensional correlation map measured with low-field and/orintermediate-field NMR and the comparison is a change in an area under a¹H T₁-T₂ relaxation time plot from T₂ of 0.1 ms to 300 ms and T₁ of 0.1ms to 300 ms; Element 47: wherein the NMR measurements are imagingmeasured with intermediate-field and/or high-field NMR the comparison isa change in a T₂- and T₁-relaxation corrected signal for a fluid withinspatial boundaries of the core sample; Element 48: wherein thehydrophobic NMR exchange fluid is hydraulically exchanged for thehydrophilic fluid in the core sample; Element 49: Element 48 and themethod further comprising: hydraulically exchanging the hydrophilicfluid in the core sample and the hydrophobic NMR exchange fluid; takinga third NMR measurement of the fluids in the core sample after thesecond hydraulic exchange; and deriving a second property of the coresample based on the porosity and a comparison between the second NMRmeasurement and the third NMR measurement, wherein the property of thecore sample is selected from the group consisting of a recoverable watervolume, an irreducible water volume, an immobile volume, and anycombination thereof; Element 50: wherein the hydrophilic NMR exchangefluid is hydraulically exchanged for the hydrophobic fluid in the coresample; and Element 51: Element 50 and the method further comprising:hydraulically exchanging the hydrophobic fluid in the core sample andthe hydrophilic NMR exchange fluid; taking a third NMR measurement ofthe fluids in the core sample after the second hydraulic exchange; andderiving a second property of the core sample based on the porosity anda comparison between the second NMR measurement and the third NMRmeasurement, wherein the property of the core sample is selected fromthe group consisting of a recoverable oil volume, an irreduciblehydrocarbon volume, an immobile volume, and any combination thereof; andElement 52: performing the method for a plurality of core samples;corresponding the pore type to the lengths along a wellbore from whichthe corresponding core samples were taken; and estimating a formationpore type at lengths along the wellbore between where the plurality ofcore samples were taken to produce an artificial NMR log. Examples ofcombinations can include, but are not limited to, two or more ofElements 42-27 in combination; one or more of Elements 42-47 incombination with one or more of Elements 32-36; one or more of Elements42-47 (optionally in combination with one or more of Elements 32-36) incombination with Element 48 (and optionally Element 49) or with Element50 (and optionally Element 51); one or more of Elements 35, 36, and 52in combination with one or more of Elements 32-34; one or more ofElements 32, 33, 34, 35, 36, and 52 in combination with Element 48 (andoptionally Element 49) or with Element 50 (and optionally Element 51);and one or more of Elements 7-11 in combination with one or more ofElements 42-52.

Embodiment A1 is a method comprising: saturating a core sample with aNMR saturation fluid, wherein the core sample has a permeability of mDor less, to achieve a saturated core sample; taking a NMR measurement ofthe saturated core sample; and determining a porosity of the core samplebased on a correlation between the NMR measurement and a NMR signal tofluid volume calibration. Embodiment A2 is the method of Embodiment A1,wherein the NMR measurement is ¹H spectroscopy measured with high-fieldNMR and the correlation is between an area under a ¹H spectrum of afluid in the core sample from 10 ppm to 0 ppm and the NMR signal tofluid volume calibration. Embodiment A3 is the method of Embodiment Al,wherein the NMR measurement is ¹H T₁/T₂ ratio measured with low-fieldand/or intermediate-field NMR and the correlation is between an areaunder a ¹H T₁/T₂ ratio of 1<¹H T₁/T₂ ratio≤100 of a fluid in the coresample and the NMR signal to fluid volume calibration. Embodiment A4 isthe method of Embodiment A1, wherein the NMR measurement is T₂ NMRsignal intensity as a function of refocusing delay and the correlationis between a y-value at a y-intercept of an extrapolation of the T₂ NMRsignal intensity including x=0 and the NMR signal to fluid volumecalibration. Embodiment A5 is the method of Embodiment Al, wherein theNMR measurement is ¹H T₂ relaxation times measured with low-field and/orintermediate-field NMR and the correlation is between an area under a ¹HT₂ relaxation time spectrum of the core sample from 0.1 ms to 300 ms andthe NMR signal to fluid volume calibration. Embodiment A6 is the methodof Embodiment A1, wherein the NMR measurement is ¹H T₁-T₂ 2-dimensionalcorrelation map measured with low-field and/or intermediate-field NMRand the correlation is between an area under a ¹H T₁-T₂ relaxation timeplot of fluid in the core sample from T₂ of 0.1 ms to 300 ms and T, of0.1 ms to 300 ms and the NMR signal to fluid volume calibration.Embodiment A7 is the method of Embodiment A1, wherein the NMRmeasurement is imaging measured with intermediate-field and/orhigh-field NMR and the correlation is between a T₂- and T₁-relaxationcorrected signal for a fluid within spatial boundaries of the coresample and the NMR signal to fluid volume calibration. Embodiment A8 isthe method of any preceding Embodiment A#, wherein the NMR saturationfluid comprises dodecane. Embodiment A9 is the method of any precedingEmbodiment A#, wherein the NMR saturation fluid comprises a mixture ofsynthetic paraffins. Embodiment A10 is the method of any precedingEmbodiment A#, wherein the NMR saturation fluid is hydrophobic.Embodiment All is the method of any one of Embodiment A1-A9, wherein theNMR saturation fluid is hydrophilic. Embodiment A12 is the method of anypreceding Embodiment A# further comprising: taking a mass of the coresample before and after hydraulic exchange. Embodiment A13 is the methodof any preceding Embodiment A# further comprising: deriving a coresample property based on at least the porosity and the NMR measurement,wherein the core sample property is one or more selected from the groupconsisting of: a pore type distribution, a nanopore oil volume, ananopore water volume, a micropore oil volume, a micropore water volume,a macropore oil volume, and a macropore water volume. Embodiment A14 isthe method of Embodiment A13 further comprising: performing the methodfor a plurality of core samples; corresponding the core sampleproperties to the lengths along a wellbore from which the correspondingcore samples were taken; and estimating a formation propertycorresponding to the core sample property at lengths along the wellborebetween where the plurality of core samples were taken. Embodiment Al 5is the method of any preceding Embodiment A# further comprising: whereinthe NMR measurement is a first NMR measurement; hydraulically exchanginga fluid in the core sample with a NMR exchange fluid; taking a secondNMR measurement of the core sample after hydraulic exchange; andderiving a core sample property based on at least the porosity and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the core sample property is one or more selectedfrom the group consisting of: a recoverable oil volume, a recoverablewater volume, an irreducible hydrocarbon volume, an irreducible watervolume, and an immobile fluid volume. Embodiment A16 is the method ofclaim Embodiment A15 further comprising: performing the method for aplurality of core samples; corresponding the core sample properties tothe lengths along a wellbore from which the corresponding core sampleswere taken; and estimating a formation property corresponding to thecore sample property at lengths along the wellbore between where theplurality of core samples were taken. Embodiment A17 is the method ofone of Embodiment A1-A16 further comprising: providing an NMR log havingporosity data of a wellbore from which the core sample was extracted;and calibrating the porosity data of the NMR log based on a comparisonof the porosity data at a corresponding length along the wellbore to theporosity of the core sample. Embodiment A18 is the method of one ofEmbodiment A1-A16 further comprising: performing the method for aplurality of core samples; corresponding the porosities to the lengthsalong a wellbore from which the corresponding core samples were taken;and estimating a formation porosity at lengths along the wellborebetween where the plurality of core samples were taken to produce anartificial NMR log.

Embodiment B1 is a method comprising: determining a porosity of a coresample, wherein the core sample has a permeability of 100 mD or less;saturating the core sample with a NMR saturation fluid to achieve asaturated core sample; taking a NMR measurement of fluids in thesaturated core sample; deriving a volume for a pore type based on theporosity based on a correlation between the NMR measurement and a NMRsignal to fluid volume calibration, wherein the pore type is selectedfrom the group consisting of a nanopore, a micropore, a macropore, andany combination thereof. Embodiment B2 is the method of Embodiment B1,wherein the NMR measurement is ¹H T₁/T₂ ratio measured with low-fieldand/or intermediate-field NMR and the correlation is between the NMRsignal to fluid volume calibration and the ¹H T₁/T₂ ratio for oneselected from the group consisting of 10≤¹H T₁/T₂<100 for the nanopores,3≤¹H T₁/T₂<10 for the micropores, 1≤¹H T₁/T₂<3 for the macropores, andany combination thereof. Embodiment B3 is the method of Embodiment B1,wherein the NMR measurement is T₂ NMR signal intensity as a function ofrefocusing delay and the correlation is between the NMR signal to fluidvolume calibration and a multi-exponential fit of the T₂ NMR signalintensity as a function of refocusing delay where a slope of eachexponential factor in the multi-exponential fit relates to the pore typeand a pre-exponential factor of each exponential factor in themulti-exponential fit relates to the volume of the pore type. EmbodimentB4 is the method of Embodiment B1, wherein the NMR measurement is ¹H T₂relaxation times measured with low-field and/or intermediate-field NMRand the correlation is between the NMR signal to fluid volumecalibration and an area under a ¹H T₂ relaxation time spectrum for oneselected from the group consisting of 0.1 ms≤T₂<1.5 ms for thenanopores, 1.5 ms≤T₂<30 ms for the micropores, 30 ms≤T₂<300 ms for themacropores, and any combination thereof. Embodiment B5 is the method ofEmbodiment B1, wherein the NMR measurement is ¹H T₁-T₂ 2-dimensionalcorrelation map measured with low-field and/or intermediate-field NMRand the correlation is between the NMR signal to fluid volumecalibration and an area under the ¹H T₁-T₂ 2-dimensional correlation mapfor one selected from the group consisting of 0.1 ms≤T₂<1.5 ms for thenanopores, 1.5 ms≤T₂<30 ms for the micropores, 30 ms≤T₂<300 ms for themacropores, and any combination thereof. Embodiment B6 is the method ofEmbodiment B1, wherein the NMR measurement is diffusometry and thecorrelation is between the NMR signal to fluid volume calibration and aT₂- and T₁-relaxation corrected area under a diffusion spectrum of thefluids in the core sample for 1×10⁻¹⁴ m²/s<diffusion rate≤1×10⁻¹¹ m²/sfor nanopores and/or for 1×10⁻¹¹ m²/s<diffusion rate≤1×10⁻⁹ m²/s formicropores. Embodiment B7 is the method of Embodiment B1, wherein theNMR measurement is T₂-weighted imaging and the correlation is betweenthe NMR signal to fluid volume calibration and a T₂- and T₁-relaxationcorrected signal for the fluids within spatial boundaries of the coresample where the T₂-weight is 0.1 ms≤T₂<1.5 ms for the nanopores, wherethe T₂-weight is 1.5 ms≤T₂<30 ms for the micropores, and where theT₂-weight is for 30 ms≤T₂<300 ms for the macropores. Embodiment B8 isthe method of any preceding Embodiments B# further comprising:performing the method for a plurality of core samples; corresponding thepore type to the lengths along a wellbore from which the correspondingcore samples were taken; and estimating a formation pore type at lengthsalong the wellbore between where the plurality of core samples weretaken to produce an artificial NMR log. Embodiment B9 is the method ofany preceding Embodiments B#, wherein the NMR saturation fluid comprisesdodecane. Embodiment B10 is the method of any preceding Embodiments B#,wherein the NMR saturation fluid comprises a mixture of syntheticparaffins. Embodiment B11 is the method of any preceding Embodiments B#,wherein the NMR saturation fluid is hydrophobic. Embodiment B12 is themethod of any one of Embodiments B1-B8, wherein the NMR saturation fluidis hydrophilic. Embodiment B13 is a method comprising: determining aporosity of a core sample, wherein the core sample has a permeability of100 milliDarcy (mD) or less; saturating the core sample with a NMRsaturation fluid to achieve a saturated core sample; taking a first NMRmeasurement of the fluid in the saturated core sample; hydraulicallyexchanging a hydrophobic fluid or a hydrophilic fluid in the core samplein a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity and a comparison between the first NMR measurementand the second NMR measurement, wherein the property of the core sampleis selected from the first group consisting of a recoverable nanoporeoil volume, a recoverable micropore oil volume, a recoverable macroporeoil volume, an irreducible nanopore hydrocarbon volume, an irreduciblemicropore hydrocarbon volume, an irreducible macropore hydrocarbonvolume, and any combination thereof for the hydrophilic NMR exchangefluid or is selected from the second group consisting of a recoverablenanopore water volume, a recoverable micropore water volume, arecoverable macropore water volume, an irreducible nanopore watervolume, an irreducible micropore water volume, an irreducible macroporewater volume, and any combination thereof for the hydrophobic NMRexchange fluid. Embodiment B14 is the method of Embodiment B13, whereinthe NMR measurement is a ¹H T₁/T₂ ratio measured with low-field and/orintermediate-field NMR and the comparison is a change in the ¹H T₁/T₂ratio for one selected from the group consisting of 10≤¹H T₁/T₂<100 forthe nanopore volumes, 3 <¹H T₁/T₂<10 for the micropore volumes, 1≤¹HT₁/T₂<3 for the macropore volumes, and any combination thereof.Embodiment B15 is the method of Embodiment B13, wherein the NMRmeasurement is T₂ NMR signal intensity as a function of refocusing delayand the comparison a change in a multi-exponential fit of the T₂ NMRsignal intensity as a function of refocusing delay where a slope of eachexponential factor in the multi-exponential fit relates to a pore typeand a pre-exponential factor of each exponential factor in themulti-exponential fit relates to a volume of the pore type. EmbodimentB16 is the method of Embodiment B13, wherein the NMR measurement is ¹HT₂ relaxation times measured with low-field and/or intermediate-fieldNMR and the comparison is a change in an area under a ¹H T₂ relaxationtime spectrum for one selected from the group consisting of 0.1ms≤T₂<1.5 ms for the nanopore volumes, 1.5 ms≤T₂<30 ms for the microporevolumes, 30 ms≤T₂<300 ms for the macropore volumes, and any combinationthereof. Embodiment B17 is the method of Embodiment B13, wherein the NMRmeasurement is ¹H T₁-T₂ 2-dimensional correlation map measured withlow-field and/or intermediate-field NMR and the comparison a change inan area under the ¹H T₁-T₂ 2-dimensional correlation map for oneselected from the group consisting of 0.1 ms≤T₂<1.5 ms for the nanoporevolumes, 1.5 ms≤T₂<30 ms for the micropore volumes, 30 ms≤T₂<300 ms forthe macropore volumes, and any combination thereof. Embodiment B18 isthe method of Embodiment B13, wherein the NMR measurement isdiffusometry and the comparison is a change a T₂- and T₁-relaxationcorrected area under a diffusion spectrum of the fluids in the coresample for 1×10⁻¹⁴ m²/s<diffusion rate≤1×10⁻for nanopore volumes and/orfor 1×10⁻¹¹ m²/s<diffusion rate≤1×10⁻⁹ m²/s for micropore volumes.Embodiment B19 is the method of Embodiment B13, wherein the NMRmeasurement is T₂-weighted imaging and the comparison is for a change ina T₂- and T₁-relaxation corrected signal for the fluids within spatialboundaries of the core sample where the T₂-weight is 0.1 ms≤T₂<1.5 msfor the nanopore volumes, where the T₂-weight is 1.5 ms≤T₂<30 ms for themicropore volumes, and where the T₂-weight is for 30 ms≤T₂<300 ms forthe macropore volumes. Embodiment B20 is the method of one ofEmbodiments B13-B19 further comprising, wherein the hydrophobic NMRexchange fluid is hydraulically exchanged for the hydrophilic fluid inthe core sample. Embodiment B21 is the method of Embodiment B20 furthercomprising: hydraulically exchanging the hydrophilic fluid in the coresample and the hydrophobic NMR exchange fluid; taking a third NMRmeasurement of the fluid in the core sample after the second hydraulicexchange; and deriving a second property of the core sample based on theporosity and a comparison between the second NMR measurement and thethird NMR measurement, wherein the property of the core sample isselected from the group consisting of the recoverable nanopore watervolume, the recoverable micropore water volume, the recoverablemacropore water volume, the irreducible nanopore water volume, theirreducible micropore water volume, the irreducible macropore watervolume, an immobile nanopore volume, an immobile micropore volume, animmobile macropore volume, and any combination thereof. Embodiment B22is the method of one of Embodiments B13-B19 further comprising: whereinthe hydrophilic NMR exchange fluid is hydraulically exchanged for thehydrophobic fluid in the core sample. Embodiment B23 is the method ofEmbodiment B22 further comprising: hydraulically exchanging thehydrophobic fluid in the core sample and the hydrophilic NMR exchangefluid; taking a third NMR measurement of the fluid in the core sampleafter the second hydraulic exchange; and deriving a second property ofthe core sample based on the porosity and a comparison between thesecond NMR measurement and the third NMR measurement, wherein theproperty of the core sample is selected from the first group consistingof the recoverable nanopore oil volume, the recoverable micropore oilvolume, the recoverable macropore oil volume, the irreducible nanoporehydrocarbon volume, the irreducible micropore hydrocarbon volume, theirreducible macropore hydrocarbon volume, an immobile nanopore volume,an immobile micropore volume, an immobile macropore volume, and anycombination thereof. Embodiment B24 is the method of one of EmbodimentsB13-B23 further comprising: performing the method for a plurality ofcore samples; corresponding the pore type to the lengths along awellbore from which the corresponding core samples were taken; andestimating the first property and optionally the second property atlengths along the wellbore between where the plurality of core sampleswere taken to produce an artificial NMR log. Embodiment B25 is themethod of one of Embodiments B13-B24, wherein the NMR saturation fluidcomprises dodecane. Embodiment B26 is the method of one of EmbodimentsB13-B24, wherein the NMR saturation fluid comprises a mixture ofsynthetic paraffins. Embodiment B27 is the method of one of EmbodimentsB13-B26, wherein the NMR saturation fluid is hydrophobic. Embodiment B28is the method of one of Embodiments B13-B24, wherein the NMR saturationfluid is hydrophilic. Embodiment B29 is the method of one of EmbodimentsB13-B28 further comprising: taking a mass of the core sample before andafter hydraulic exchange. Embodiment B30 is the method of one ofEmbodiments B13-B29 further comprising: performing compositionalanalysis on fluids that elutes from the core sample during hydraulicexchange.

Embodiment C1. A method comprising: determining a porosity of a coresample, wherein the core sample has a permeability of 100 mD or less;saturating the core sample with an NMR saturation fluid; taking a firstNMR measurement of fluid in the core sample; hydraulically exchanging ahydrophobic fluid or a hydrophilic fluid in the core sample in ahydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid,respectively; taking a second NMR measurement of the fluid in the coresample after hydraulic exchange; deriving a property of the core samplebased on the porosity, a NMR signal to fluid volume calibration, and acomparison between the first NMR measurement and the second NMRmeasurement, wherein the property of the core sample is selected fromthe first group consisting of a recoverable oil volume, an irreduciblehydrocarbon volume, and any combination thereof when using thehydrophilic NMR exchange fluid or is selected from the second groupconsisting of a recoverable water volume, an irreducible water volume,and any combination thereof when using the hydrophobic NMR exchangefluid. Embodiment C2 is the method of Embodiment C1, wherein the NMRmeasurement is ¹H spectroscopy measured with high-field NMR and thecomparison is a change in an area under a ¹H spectrum of a fluid in thecore sample from 10 ppm to 0 ppm. Embodiment C3 is the method ofEmbodiment C1, wherein the NMR measurement is ¹H T₁/T₂ ratio measuredwith low-field and/or intermediate-field NMR and the comparison is achange in an area an area under a ¹H T₁/T₂ ratio of 1<¹H T₁/T₂ ratio≤100of a fluid in the core sample. Embodiment C4 is the method of EmbodimentCl, wherein the NMR measurement is T₂ NMR signal intensity as a functionof refocusing delay and the comparison is in a y-value at a y-interceptof an extrapolation of the T₂ NMR signal intensity including x=0.Embodiment C5 is the method of Embodiment C1, wherein the NMRmeasurement is ¹H T₂ relaxation times measured with low-field and/orintermediate-field NMR and the comparison is a change in an area under a¹H T₂ relaxation time spectrum of the core sample from 0.1 ms to 300 ms.Embodiment C6 is the method of Embodiment C1, wherein the NMRmeasurement is ¹H T₁-T₂ 2-dimensional correlation map measured withlow-field and/or intermediate-field NMR and the comparison is a changein an area under a ¹H T₁-T₂ relaxation time plot of fluid in the coresample from T₂ of 0.1 ms to 300 ms and T₁ of 0.1 ms to 300 ms and theNMR signal to fluid volume calibration. Embodiment C7 is the method ofEmbodiment C1, wherein the NMR measurement is imaging measured withintermediate-field and/or high-field NMR the comparison is a change in aT₂- and T₁-relaxation corrected signal for a fluid within spatialboundaries of the core sample and the NMR signal to fluid volumecalibration. Embodiment C8 is the method of any preceding Embodiment C#,wherein the NMR saturation fluid comprises dodecane. Embodiment C9 isthe method of any preceding Embodiment C#, wherein the NMR saturationfluid comprises a mixture of synthetic paraffins. Embodiment C10 is themethod of any preceding Embodiment C#, wherein the NMR saturation fluidis hydrophobic. Embodiment C11 is the method of any one of EmbodimentC1-C9, wherein the NMR saturation fluid is hydrophilic. Embodiment C12is the method of one of Embodiment C1-C11 further comprising, whereinthe hydrophobic NMR exchange fluid is hydraulically exchanged for thehydrophilic fluid in the core sample. Embodiment C13 is the method ofEmbodiment C9 further comprising: hydraulically exchanging thehydrophilic fluid in the core sample and the hydrophobic NMR exchangefluid; taking a third NMR measurement of the fluid in the core sampleafter the second hydraulic exchange; and deriving a second property ofthe core sample based on the porosity and a comparison between thesecond NMR measurement and the third NMR measurement, wherein theproperty of the core sample is selected from the group consisting of arecoverable water volume, an irreducible water volume, an immobilevolume, and any combination thereof. Embodiment C14 is the method of oneof Embodiment C1-C11 further comprising: wherein the hydrophilic NMRexchange fluid is hydraulically exchanged for the hydrophobic fluid inthe core sample. Embodiment C15 is the method of claim Embodiment C11further comprising: hydraulically exchanging the hydrophobic fluid inthe core sample and the hydrophilic NMR exchange fluid; taking a thirdNMR measurement of the fluid in the core sample after the secondhydraulic exchange; and deriving a second property of the core samplebased on the porosity and a comparison between the second NMRmeasurement and the third NMR measurement, wherein the property of thecore sample is selected from the group consisting of a recoverable oilvolume, an irreducible hydrocarbon volume, an immobile volume, and anycombination thereof. Embodiment C16 is the method of any precedingEmbodiment C# further comprising: performing the method for a pluralityof core samples; corresponding the pore type to the lengths along awellbore from which the corresponding core samples were taken; andestimating a formation pore type at lengths along the wellbore betweenwhere the plurality of core samples were taken to produce an artificialNMR log. Embodiment C17 is the method of any preceding Embodiment C#further comprising: taking a mass of the core sample before and afterhydraulic exchange. Embodiment C18 is the method of any precedingEmbodiment C# further comprising: performing compositional analysis onthe hydrocarbon that elutes from the core sample during hydraulicexchange.

Unless otherwise indicated, all numbers expressing quantities ofingredients, properties such as molecular weight, reaction conditions,and so forth used in the present specification and associated claims areto be understood as being modified in all instances by the term “about.”Accordingly, unless indicated to the contrary, the numerical parametersset forth in the following specification and attached claims areapproximations that may vary depending upon the desired propertiessought to be obtained by the embodiments of the present invention. Atthe very least, and not as an attempt to limit the application of thedoctrine of equivalents to the scope of the claim, each numericalparameter should at least be construed in light of the number ofreported significant digits and by applying ordinary roundingtechniques.

One or more illustrative embodiments incorporating the inventionembodiments disclosed herein are presented herein. Not all features of aphysical implementation are described or shown in this application forthe sake of clarity. It is understood that in the development of aphysical embodiment incorporating the embodiments of the presentinvention, numerous implementation-specific decisions must be made toachieve the developer's goals, such as compliance with system-related,business-related, government-related and other constraints, which varyby implementation and from time to time. While a developer's effortsmight be time-consuming, such efforts would be, nevertheless, a routineundertaking for those of ordinary skill in the art and having benefit ofthis disclosure.

While compositions and methods are described herein in terms of“comprising” various components or steps, the compositions and methodscan also “consist essentially of” or “consist of” the various componentsand steps.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention. The invention illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces.

The invention claimed is:
 1. A method comprising: saturating a coresample with a nuclear magnetic resonance (NMR) saturation fluid, whereinthe core sample has a permeability of 100 milliDarcy (mD) or less, toachieve a saturated core sample; taking a NMR measurement of fluids inthe saturated core sample; determining a porosity of the core samplebased on a correlation between the NMR measurement and a NMR signal tofluid volume calibration.
 2. The method of claim 1, wherein the NMRmeasurement is ¹H spectroscopy measured with high-field NMR and thecorrelation is between an area under a ¹H spectrum from 10 ppm to 0 ppmand the NMR signal to fluid volume calibration.
 3. The method of claim1, wherein the NMR measurement is ¹H T₁/T₂ ratio measured with low-fieldand/or intermediate-field NMR and the correlation is between an areaunder a ¹H T₁/T₂ ratio of 1<¹H T₁/T₂ ratio≤100 and the NMR signal tofluid volume calibration.
 4. The method of claim 1, wherein the NMRmeasurement is T₂ NMR signal intensity as a function of refocusing delayand the correlation is between a y-value at a y-intercept of anextrapolation of the T₂ NMR signal intensity including x=0 and the NMRsignal to fluid volume calibration.
 5. The method of claim 1, whereinthe NMR measurement is ¹H T₂ relaxation times measured with low-fieldand/or intermediate-field NMR and the correlation is between an areaunder a ¹H T₂ relaxation time spectrum from 0.1 ms to 300 ms and the NMRsignal to fluid volume calibration.
 6. The method of claim 1, whereinthe NMR measurement is ¹H T₁-T₂ 2-dimensional correlation map measuredwith low-field and/or intermediate-field NMR and the correlation isbetween an area under a¹H T₁-T₂ relaxation time plot from T₂ of 0.1 msto 300 ms and T₁ of 0.1 ms to 300 ms and the NMR signal to fluid volumecalibration.
 7. The method of claim 1, wherein the NMR measurement isimaging measured with intermediate-field and/or high-field NMR and thecorrelation is between a T₂- and T₁-relaxation corrected signal for thefluids within spatial boundaries of the core sample and the NMR signalto fluid volume calibration.
 8. The method of claim 1, wherein the NMRsaturation fluid is hydrophobic.
 9. The method of claim 1, wherein theNMR saturation fluid comprises dodecane.
 10. The method of claim 1,wherein the NMR saturation fluid comprises a mixture of syntheticparaffins.
 11. The method of claim 1, wherein the NMR saturation fluidis hydrophilic.
 12. The method of claim 1, further comprising: taking amass of the core sample before and after saturating.
 13. The method ofclaim 1, further comprising: deriving a core sample property based on atleast the porosity and the NMR measurement, wherein the core sampleproperty is one or more selected from the group consisting of: a poretype distribution, a nanopore oil volume, a nanopore water volume, amicropore oil volume, a micropore water volume, a macropore oil volume,and a macropore water volume.
 14. The method of claim 13, furthercomprising: performing the method for a plurality of core samples;corresponding the core sample properties to the lengths along a wellborefrom which the corresponding core samples were taken; and estimating aformation property corresponding to the core sample property at lengthsalong the wellbore between where the plurality of core samples weretaken.
 15. The method of claim 1, further comprising: wherein the NMRmeasurement is a first NMR measurement; hydraulically exchanging a fluidin the core sample with a NMR exchange fluid; taking a second NMRmeasurement of the core sample after hydraulic exchange; and deriving acore sample property based on at least the porosity and a comparisonbetween the first NMR measurement and the second NMR measurement,wherein the core sample property is one or more selected from the groupconsisting of: a recoverable oil volume, a recoverable water volume, anirreducible hydrocarbon volume, an irreducible water volume, and animmobile fluid volume.
 16. The method of claim 15, further comprising:performing the method for a plurality of core samples; corresponding thecore sample properties to the lengths along a wellbore from which thecorresponding core samples were taken; and estimating a formationproperty corresponding to the core sample property at lengths along thewellbore between where the plurality of core samples were taken.
 17. Themethod of claim 1, further comprising: providing a NMR log havingporosity data of a wellbore from which the core sample was extracted;calibrating the porosity data of the NMR log based on a comparison ofthe porosity data at a corresponding length along the wellbore to theporosity of the core sample.
 18. The method of claim 1, furthercomprising: performing the method for a plurality of core samples;corresponding the porosities to the lengths along a wellbore from whichthe corresponding core samples were taken; and estimating a formationporosity at lengths along the wellbore between where the plurality ofcore samples were taken to produce an artificial NMR log.